10-K 1 d464688d10k.htm FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012 FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
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Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   76-0146568
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046

(Address of principal executive offices)

Registrant’s telephone number, including area code (832) 636-1000

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class    Name of each exchange on which registered
Common Stock, par value $0.10 per share    New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 29, 2012, was $33.0 billion based on the closing price as reported on the New York Stock Exchange.

The number of shares outstanding of the Company’s common stock at January 31, 2013, is shown below:

 

Title of Class    Number of Shares Outstanding
Common Stock, par value $0.10 per share    500,565,966

Documents Incorporated By Reference

Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 14, 2013 (to be filed with the Securities and Exchange Commission prior to April 4, 2013), are incorporated by reference into Part III of this Form 10-K.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

                Page  

PART I

   

Items 1 and 2.

 

Business and Properties

    2  
   

General

    2  
   

Oil and Gas Properties and Activities

    3  
     

United States

    4  
     

International

    10   
     

Proved Reserves

    13  
     

Sales Volumes, Prices, and Production Costs

    18  
     

Delivery Commitments

    19  
     

Properties and Leases

    19  
     

Drilling Program

    19  
     

Drilling Statistics

    20  
     

Productive Wells

    21  
   

Midstream Properties and Activities

    21  
   

Marketing Activities

    23  
   

Competition

    24  
   

Segment Information

    24  
   

Employees

    24  
    Regulatory Matters, Environmental, and Additional Factors Affecting Business     24  
   

Title to Properties

    31  
   

Executive Officers of the Registrant

    31  

Item 1A.

 

Risk Factors

    33  

Item 1B.

 

Unresolved Staff Comments

    49  

Item 3.

 

Legal Proceedings

    49  

Item 4.

 

Mine Safety Disclosures

    49  

PART II

   

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities

    50  

Item 6.

  Selected Financial Data     53  

Item 7.

 

Management’s Discussion and Analysis of Financial Condition
and Results of Operations

    54  

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk     86  

Item 8.

  Financial Statements and Supplementary Data     88  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure

    160  

Item 9A.

  Controls and Procedures     160  

Item 9B.

  Other Information     160  

PART III

   

Item 10.

  Directors, Executive Officers, and Corporate Governance     161  

Item 11.

  Executive Compensation     161  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters

    161  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    161  

Item 14.

 

Principal Accountant Fees and Services

    161  

PART IV

   

Item 15.

 

Exhibits, Financial Statement Schedules

    162  


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PART I

Items 1 and 2.  Business and Properties

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Risk Factors under Item 1A of this Form 10-K.

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 2.6 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2012. Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko’s asset portfolio is aimed at delivering long-term value to stakeholders by combining a large inventory of development opportunities in the U.S. onshore with high-potential worldwide offshore exploration and development activities.

Anadarko’s asset portfolio includes U.S. onshore resource plays in the Rocky Mountains area, the southern United States, and the Appalachian basin. The Company is also among the largest independent producers in the deepwater Gulf of Mexico, and has production and exploration activities worldwide, including high-potential basins located in Algeria, Mozambique, Ghana, China, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, Brazil, Alaska, New Zealand, and other countries.

Anadarko is committed to producing energy in a manner that protects the environment and public health. Anadarko’s focus is to deliver resources to the world while upholding the Company’s core values of integrity and trust, servant leadership, people and passion, commercial focus, and open communication in all business activities.

Anadarko’s business segments are managed separately due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are as follows:

Oil and gas exploration and production—This segment explores for and produces natural gas, crude oil, condensate, and natural gas liquids (NGLs).

Midstream—This segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The Company owns and operates gathering, processing, treating, and transportation systems in the United States for natural gas, crude oil, and NGLs.

Marketing—This segment sells much of Anadarko’s production, as well as third-party purchased volumes. The Company actively markets oil, natural gas, and NGLs in the United States, and oil from Algeria, China, and Ghana.

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046, and its telephone number is (832) 636-1000.

Available Information  The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements, and other items with the Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its website located at www.anadarko.com/Investor/Pages/SECFilings.aspx. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this report, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216 or (800) 262-9361.

 

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The public may also read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Anadarko, that file electronically with the SEC.

OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s significant oil and natural-gas exploration and production operations.

 

LOGO

 

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United States

Overview  Anadarko’s U.S. operations include oil and natural-gas exploration and production onshore in the Lower 48 states, the deepwater Gulf of Mexico, and onshore Alaska. The Company’s U.S. operations accounted for 89% of total sales volumes during 2012 and 90% of total proved reserves at year-end 2012.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties are located in Colorado, Utah, and Wyoming. The assets are a combination of oil and natural-gas plays with significant growth and capital investment in areas that offer higher liquids yields (liquids-rich areas). Anadarko operates approximately 13,100 wells and owns an interest in approximately 10,000 non-operated wells in the Rockies. Anadarko operates fractured carbonate/shale reservoirs, tight-gas assets, coalbed methane (CBM) natural-gas assets, and enhanced oil recovery (EOR) projects within the region. The Company also has fee ownership of mineral rights under approximately 8 million acres that pass through Colorado, Wyoming, and into Utah (known as the Land Grant). Management considers the Land Grant a significant competitive advantage for Anadarko as it offers drilling opportunities for the Company in liquids-rich areas and allows the Company to capture incremental royalty revenue from third-party activity on Land Grant acreage.

The Company believes the competitive advantages provided by mineral ownership in the Land Grant, its liquids-rich reservoirs, strong well performance, low development costs, and a large expandable midstream infrastructure each provide tangible benefits and position the Company to accelerate its Wattenberg horizontal drilling program. Activities in the Rockies focus on expanding existing fields to increase production and adding proved reserves through horizontal drilling, infill drilling, and down-spacing operations.

In 2012, total-year Rockies sales volumes increased 6% over 2011, with an 11% increase in liquids volumes. The Company drilled 794 wells and completed 846 wells during 2012. The Company plans to increase the number of horizontal wells drilled from 181 in 2012 to approximately 325 in 2013, with continued focus on liquids-rich plays.

 

LOGO

 

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Wattenberg  The Wattenberg field is a liquids-rich area where Anadarko operates over 5,500 wells. The field contains the Niobrara and Codell naturally fractured carbonate formations that hold liquids and natural gas. During 2012, the Company drilled 136 vertical/directional wells and 176 horizontal wells. Sales volumes in the Wattenberg field increased 25% compared to 2011, with a year-over-year 30% increase in liquids volumes. Horizontal drilling results in the Wattenberg field have shown strong initial production rates with average liquids yields of approximately 65%. The Company also has identified approximately 4,000 potential drilling locations in the Niobrara and Codell formations that provide substantial opportunity for expanding Anadarko’s activity. In 2013, the Company plans to increase its activity in the Wattenberg field by deploying eleven horizontal rigs.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets where the Company utilizes refrigeration and cryogenic processing facilities to extract NGLs from the gas stream. Anadarko has expanded the cryogenic facilities at its Chipeta plant to increase contracted cryogenic processing capacity, which is capable of recovering an additional 15,000 barrels of NGLs per day.

The Company operates over 2,400 wells in the Greater Natural Buttes area, drilled 341 wells in 2012, and increased year-over-year operated sales volumes from the area by 19%. Anadarko drilled and completed 70 new development wells in the lower Mesaverde Blackhawk formation during 2012 and has identified more than 8,000 potential locations in this formation for future development. Many of these locations are infill drilling opportunities focused on down-spacing from 40-acre well density to 10-acre well density.

Powder River  The Company drilled nine horizontal wells in the Powder River basin during 2012 as part of a multi-objective horizontal exploration program targeting liquids-rich plays. Anadarko controls over 350,000 acres of deep rights within the Powder River basin.

Coalbed Methane Properties  Anadarko operates approximately 2,400 low-cost CBM wells and owns an interest in approximately 4,100 non-operated CBM wells in the Rockies, primarily located in the Powder River basin in Wyoming and the Helper and Clawson fields in Utah. Anadarko controls over 650,000 acres of shallow rights within the Powder River basin. CBM is natural gas that is generated and stored within coal seams. To produce CBM, water is extracted from the coal seam, resulting in reduced pressure and the release of natural gas, which flows to the wellhead. In 2012, Anadarko sold its interest in the Atlantic Rim field and reduced development activity in its CBM program as the Company continued to focus capital spending on liquids-rich opportunities. Reduced activity is expected to continue in 2013 as a result of low natural-gas prices.

Salt Creek and Monell  During 2012, the Company continued development of its Rockies EOR assets at the Salt Creek and Monell fields in Wyoming. The Company’s EOR operations increase the amount of oil that can be produced from mature reservoirs after primary and water-flood recovery methods have been completed. In April 2012, the Company entered into a carried-interest arrangement where a third party agreed to fund $400 million of development costs in exchange for a 23% interest in the Company’s EOR development at the Salt Creek field in Wyoming. At December 31, 2012, $201 million of the $400 million obligation had been funded. In 2013, the Company will continue development at the Monell field with a small drilling program planned to enhance carbon-dioxide flooding operations.

 

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Southern and Appalachia Region  Anadarko’s Southern and Appalachia Region properties are primarily located in Texas, Pennsylvania, Louisiana, Kansas, and Ohio. Operations in these areas are focused on finding and developing both natural gas and liquids from shales, tight sands, and fractured-reservoir plays. Anadarko holds an interest in approximately 4.5 million gross acres throughout the Southern and Appalachia Region. This area includes the Eagleford/Pearsall shales in South Texas, the Marcellus shale in north-central Pennsylvania, the Permian basin of West Texas, the Haynesville shale in East Texas and Louisiana, and the Utica shale in eastern Ohio.

By utilizing modernized drilling rigs and experienced crews, the region continued to experience improved drilling efficiencies in every area with respect to cycle times, while also drilling longer lateral lengths. Similar cost reductions and efficiencies were gained on completion operations. Due to lower natural-gas prices, the Company continued its focus on liquids-rich opportunities, executing on its substantial liquids-rich inventory while significantly reducing project costs.

In 2012, total-year sales volumes in the Southern and Appalachia Region increased 36% over 2011, with a 35% increase in liquids volumes. The Company drilled 513 operated horizontal wells and brought 453 wells online in 2012. The Company expects to drill approximately 455 horizontal wells in 2013.

 

LOGO

Eagleford  The Eagleford shale continues to be one of the Company’s most prolific plays, capable of generating returns in excess of 100%. The Eagleford shale also benefits from a carried-interest arrangement entered into in 2011 that conveyed 33.3% of the Company’s Eagleford and Pearsall shale assets to a third party in exchange for the funding of $1.6 billion of Anadarko’s then-future development costs. Third-party funding pursuant to the carried-interest arrangement began in the second quarter of 2011 and provided the Company $500 million of funding for 2011 and $650 million of funding for 2012. The third-party funding is expected to cover 90% of development costs until the commitment is fulfilled, which is expected to occur by year-end 2013.

 

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Anadarko currently holds 413,000 gross acres in this area. During 2012, the Company operated an average of nine rigs, spud 292 horizontal wells, and fracture stimulated 239 wells. The Company increased sales volumes by 93% year over year. During 2012, Anadarko also expanded its infield gathering-system capacity from 225 million cubic feet per day (MMcf/d) to 350 MMcf/d and sanctioned a new high-efficiency Company-operated cryogenic gas plant that is scheduled to come online in 2013. The 200 MMcf/d plant is expected to increase processing capacity and is capable of recovering approximately 30,000 barrels per day (Bbls/d) of NGLs.

Marcellus  In the Marcellus shale of the Appalachian basin, where the Company holds 760,000 gross acres, 78 operated horizontal wells were spud and 77 wells were brought online utilizing a fleet that averaged five rigs during the year. Anadarko also participated as a non-operating partner in 117 horizontal wells and 154 wells that were brought online in 2012. Anadarko’s sales volumes in the Marcellus shale increased 133% over 2011.

In 2010, Anadarko entered into a carried-interest arrangement where a third party earned a 32.5% interest in the Company’s Marcellus shale assets in exchange for funding $1.4 billion of Anadarko’s drilling costs. The third party funded 100% of the Company’s 2010 development costs and 90% of its 2011 development costs. The funding obligation was completed during July 2012.

Permian  Anadarko holds an interest in over 575,000 gross acres in the Delaware basin. Anadarko’s 2012 drilling activity primarily targeted the liquids-rich Bone Spring formation and Avalon shale. In 2012, Anadarko spud 58 operated wells, participated in 31 non-operated wells, and completed 55 operated and 29 non-operated wells in the area. Significant infrastructure was added in 2012 to allow for increased natural-gas and liquids processing. The Company had three operated rigs drilling in the Bone Spring formation and two operated rigs drilling in the Avalon shale at year-end 2012.

East Texas/Haynesville  Anadarko increased its capital program in the East Texas Carthage area in 2012, taking advantage of a liquids-rich area in the Haynesville shale. In 2012, Anadarko operated seven rigs, drilling 67 wells in the Haynesville and Cotton Valley formations and converting 60 wells to production. The Company increased sales volumes from the area by 41% year over year, while also achieving organic reserves growth.

Utica  In late 2011, the Company began an exploration program in eastern Ohio targeting the liquids-rich Utica shale. In 2012, five exploration wells were drilled throughout the Company’s 411,000 gross acres. Seven wells were completed and are currently in the production testing and evaluation phase.

 

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Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 64% working interest in 479 blocks. The Company operates seven active floating platforms, holds interests in 34 producing fields, and is in the process of delineating and developing six additional fields in the area. During 2012, the Company continued an active deepwater exploration and appraisal program in the Gulf of Mexico and is continuing to take advantage of existing infrastructure to accelerate development activities at reduced cost.

 

LOGO

The following includes the significant production, development, appraisal, and exploration activity during 2012.

Production  In March 2012, Anadarko began production at the Caesar/Tonga field (33.75% working interest) where it is currently producing from three wells. The Company is drilling a fourth development well at Caesar/Tonga, which is expected to begin producing in the second quarter of 2013.

Development Anadarko continues to advance the Lucius development with construction of the spar underway. During the third quarter of 2012, Anadarko entered into a carried-interest arrangement for the Lucius development, where a third-party partner agreed to fund $556 million of development costs to earn a 7.2% working interest. The amount of the carry obligation represents 100% of the Company’s expected future capital costs through first production. The Company holds a 27.8% working interest in the Lucius development. In December 2012, the Company drilled a successful development well, confirming and extending the Lucius field along its western flank. During 2013, the Company plans to drill four additional development wells and begin completion operations. First production from Lucius is expected in 2014.

 

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Appraisal  During 2012, Anadarko participated in drilling two appraisal wells in the Gulf of Mexico. The successful Heidelberg-2 appraisal well (44.25% working interest) encountered oil pay in high-quality Miocene sands. The Heidelberg-2 was drilled about 1.3 miles south of and 550 feet up-dip from the Heidelberg discovery. Pre-front-end engineering and design work has been finalized and Anadarko anticipates sanctioning this project in mid-2013. Another successful appraisal well was drilled at the Vito discovery (18.67% working interest) in Mississippi Canyon Block 940 and encountered oil pay in the Miocene-age reservoirs approximately 1.5 miles from the discovery well. A follow-up appraisal well was drilling at year-end 2012.

At year end, the Company-operated Shenandoah appraisal well (30% working interest) was drilling in Walker Ridge Block 51. The appraisal well is delineating the extent of the Lower Tertiary reservoirs found by the 2009 Shenandoah discovery well.

Exploration  At year end, two exploration wells were drilling in Walker Ridge within the same mini-basin as the 2009 Shenandoah discovery. The Coronado exploration well (15% working interest) was spud during the second quarter of 2012 and the Yucatan exploration well (15% working interest) was spud during the third quarter of 2012. Both wells will test the Lower Tertiary section.

The Phobos exploration well (30% working interest) was spud in December 2012 and is a multiple-objective test of the Pliocene, Miocene, and Upper and Lower Wilcox sections. The Phobos well is located approximately 12 miles south of the Lucius field. Anadarko expects to be fully carried on the estimated capital cost of the Phobos well as the result of two separate farmout agreements, the latest of which was finalized during the third quarter of 2012.

During 2012, the Company drilled the Spartacus exploration well (63.3% working interest) approximately 15 miles from the Lucius discovery in the Gulf of Mexico. The well was unsuccessful.

Alaska  Anadarko’s oil and natural-gas production and development activity in Alaska is concentrated primarily on the North Slope. Development activity continued at the Colville River Unit through 2012 with eight additional wells drilled in the Alpine and its satellite fields. In the fourth quarter of 2012, the Company sanctioned the Alpine West development, a 15- to 20-well extension of the Alpine field. In 2013, the Company anticipates participating in approximately 10 additional development wells.

 

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International

Overview  Anadarko’s significant international oil and natural-gas production and development operations are located in Mozambique, Algeria, Ghana, and China. The Company also has exploration acreage in Ghana, Mozambique, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, China, New Zealand, Brazil and other countries. International locations accounted for 11% of Anadarko’s total sales volumes and 27% of sales revenues during 2012, as well as 10% of total proved reserves at year-end 2012. Anadarko drilled 51 wells in international areas in 2012, resulting in new natural-gas discoveries in Mozambique and oil discoveries in Ghana and Côte d’Ivoire. In 2013, the Company expects to drill approximately 40 development and 20 exploration wells at various international locations.

 

LOGO

Mozambique  Anadarko operates two blocks (one onshore and one offshore) in Mozambique totaling approximately six million gross acres.

In 2012, the Company drilled two natural-gas discoveries, Golfinho and Atum, in a reservoir complex located entirely within Offshore Area 1 of the Rovuma basin, where Anadarko is the operator and holds a 36.5% working interest. The Golfinho and Atum discovery wells encountered natural-gas pay in two high-quality Oligocene fan systems. These discoveries subsequently were appraised with four successful wells (Golfinho 2, 3, and 4 and Atum 2), which confirmed the southern and down-dip extent of the reservoir. Future appraisal drilling will focus on confirming the northern and up-dip extent of the reservoir, which is age-equivalent to, but geologically distinct from, the Company’s 2010 and 2011 discoveries in the Prosperidade field. The Company drilled the Perola Negra and Barracuda exploration wells, both of which were unsuccessful.

 

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The Company also completed the appraisal-drilling and well-testing program in the Prosperidade field where Anadarko is the operator and holds a 36.5% working interest. The reservoir straddles Offshore Areas 1 and 4 and contains the Windjammer, Lagosta, Barquentine, and Camarão discoveries. The Prosperidade field appraisal program consisted of the drilling of three successful wells (Lagosta 2 and 3 and Barquentine 4) and a comprehensive testing program. In addition, the Company signed a Heads of Agreement (HOA) with Eni S.p.A. (Eni), establishing foundational principles for the coordinated development of the common natural-gas reservoirs spanning both Offshore Area 1 (operated by Anadarko) and Offshore Area 4 (operated by Eni). The HOA is designed to facilitate a work program whereby the two operators will conduct separate, yet coordinated, offshore development activities, while jointly planning and constructing common onshore liquefaction facilities in the form of a liquefied natural gas (LNG) park in the Cabo Delgado Province of northern Mozambique.

During 2012, the government of Mozambique awarded the site for the LNG processing facilities. Also, Anadarko and its partners awarded Front-End Engineering and Design contracts related to the development of four 5-million tonnes per annum LNG trains, including 10 million metric tons per annum (mmtpa) for Area 1 and 10 mmtpa for Area 4. The first LNG train is expected to be completed with first delivery in 2018.

Algeria  Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404 and 208 that are governed by a Production Sharing Agreement (PSA) between Anadarko, two other parties, and Sonatrach, the national oil and gas company of Algeria. The Company is responsible for 24.5% of the development and production costs on these blocks. At December 31, 2012, all production was from fields located in Block 404, which produce through the Hassi Berkine South and Ourhoud central processing facilities. Initial production from the El Merk project in Block 208 is expected in the first quarter of 2013, with peak volumes expected to be achieved at the El Merk central processing facility during 2013. The Company drilled 20 development wells in 2012. During 2013, the Company expects to drill 18 to 20 wells.

Exceptional Profits Tax Resolution  In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company disagreed with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in 2009. In March 2012, the Company and Sonatrach resolved this dispute. The resolution provides for delivery of crude oil to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income in the first quarter of 2012 to reflect the effect of this agreement on previously recorded expenses. Additionally, the parties amended the existing PSA to increase the Company’s sales volumes and to lower the effective exceptional profits tax rate. The amendment confirmed the length of each exploitation license to be 25 years from the date the license was granted under the PSA with expiration dates ranging from December 2022 to December 2036.

Ghana  Anadarko’s exploration and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.

During 2012, the Company and its partners drilled four of eight Phase 1A wells in the Jubilee field (24% non-operated unit interest), which is included in the West Cape Three Points and the Deepwater Tano Blocks. In addition, seven existing producing wells were successfully acidized to enhance production levels and the Company exited the year with record gross production volumes for the field of more than 110,000 Bbls/d. In 2013, the Company and its partners plan to drill the remaining four Phase 1A wells in the Jubilee field.

West Cape Three Points  Jubilee tie-back development options are being evaluated in the West Cape Three Points Block (31% non-operated working interest) to maximize the value from the Teak and Akasa discoveries. During 2012, the Teak 4 appraisal well was drilled and was unsuccessful.

 

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Deepwater Tano  During 2012, the Company participated in four exploration and appraisal wells in the Deepwater Tano Block where Anadarko holds an 18% non-operated working interest.

Successful operations in the Tweneboa/Enyenra/Ntomme (TEN) complex were completed through the drilling of two appraisal wells (Enyenra 4A and Ntomme 2A) and a testing program. During the fourth quarter of 2012, the Company and its partners submitted the Plan of Development (POD) for the TEN fields to the Government of Ghana. In 2013, the Company and its partners plan to sanction and begin development of the TEN fields upon approval of the POD. The TEN development will utilize a standalone floating production, storage, and offloading vessel for production from subsea wells.

The Okure-1 exploration well targeted a slightly deeper section than the pay sections encountered in the TEN complex. The well encountered a low net-to-gross oil bearing sandstone interval in a secondary Turonian objective. The well was deemed non-commercial and was plugged and abandoned.

The Company also made an additional discovery in the Deepwater Tano Block at the Wawa exploration well, which encountered oil pay and gas-condensate pay in Turonian-aged reservoirs. Pressure data indicate that this discovery is an accumulation separate and distinct from the adjacent TEN complex and extends the presence of hydrocarbon-bearing formations more than six miles north. In 2013, the Company and its partners plan to conduct an appraisal program for the Wawa discovery.

China  Anadarko’s production and development activities in China are located offshore in Bohai Bay. Drilling resumed in the fourth quarter of 2012, with four new sidetrack wells drilled and brought online. Drilling will continue through 2013. Preparation of a development plan for the next major field expansion and project sanction are expected to be completed in the third quarter of 2013. Consistent with the terms of the petroleum contract, the Company transferred operatorship of the Bohai Bay development to CNOOC China Limited at the end of 2012. The Company maintained its average working interest of approximately 35%.

Drilling is also expected to resume on the Company’s exploration acreage in the South China Sea in the second quarter of 2013. The Liwan 21-1-1 exploration well (50% working interest) in the South China Sea spud in August 2012 and was suspended after setting surface casing due to rig commitments and weather considerations. The Company is fully carried on the well.

Liberia  The Company operates two blocks, Block 10 (80% working interest) and Block 15 (48% working interest), offshore Liberia totaling approximately 1.3 million exploration acres in the Liberian basin. Multiple Cretaceous stratigraphic prospects, similar to the Jubilee Mahogany fan, have been identified on these blocks. Block 10 exploration drilling is planned for 2013.

Sierra Leone  Anadarko operates a 55% participating interest in Block SL-07B-11 offshore Sierra Leone, which encompasses approximately 1.3 million gross acres. Multiple Upper Cretaceous fan-type prospects have been identified in the lightly explored Liberian basin. The Jupiter #1 discovery well, spud in the fourth quarter of 2011, reached total depth in 2012 and encountered hydrocarbon pay. The wellbore has been preserved for possible re-entry, as the area requires additional evaluation. The Mercury #2 appraisal well, drilled 7.5 miles northwest and approximately 1,300 feet lower than the Mercury discovery well, was unsuccessful. Data from the wells is being evaluated to determine future drilling plans.

Kenya  Anadarko owns and operates a 45% participating interest in five deepwater blocks offshore Kenya, encompassing approximately six million gross acres. The Company completed 2D and 3D seismic programs and two exploration wells are planned for 2013. Evaluation of the Company’s exploration position will commence with the Kiboko and Kubwa prospects, which will test both stratigraphic and structural play types. The Company will be largely carried on these two wells.

 

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Côte d’Ivoire  Anadarko owns working interests in three blocks offshore Côte d’Ivoire (Blocks CI-515 and CI-516 with a 45% operated working interest and Block CI-103 with a 40% non-operated working interest). Two exploration wells were drilled in 2012 on Blocks CI-105 and CI-103. The Kosrou well on Block CI-105 was unsuccessful. Anadarko and its partners elected not to enter the next phase of exploration outlined in the production sharing contract license for Block CI-105 and no longer hold a working interest in the block. The Company announced a discovery at the Paon exploration well on Block CI-103, which encountered light oil pay in a single Cretaceous fan interval. The discovery confirms that the Upper Cretaceous fan play present in Ghana extends westward into Côte d’Ivoire. Several additional prospects have been identified and an extensive exploration and appraisal program is being planned for the area.

New Zealand  Anadarko operates approximately 10 million gross exploration acres in New Zealand, with a 50% working interest in the Taranaki and Canterbury basins and a 100% working interest in the recently acquired Pegasus basin. A 3D seismic survey of approximately 1,100 square miles was completed on the Taranaki Block in 2011, and a 2D seismic survey of approximately 2,400 miles was acquired over the Canterbury Blocks. An exploration well is planned for the end of 2013 subject to rig availability.

Brazil  Anadarko holds exploration interests in approximately 750,000 gross acres in six blocks located offshore Brazil in the Campos and Espírito Santo basins. The Wahoo-4 appraisal well on Block BM-C-30 (30% working interest) encountered oil pay on the western side of the structure in which the Wahoo-1 discovery well is located. Additional appraisal on the northeastern side of the structure is planned for 2013. The Ituana appraisal well on Block BM-C-29 was plugged and abandoned and the Company is evaluating the results of the well to determine the future plans for the block. Also during 2012, the Company drilled the Requeijao and Provolone exploration wells, both of which were unsuccessful. The Company is marketing its Brazilian properties.

Indonesia  In 2012, Anadarko owned participating interests in approximately 3.4 million gross exploration acres in Indonesia through three production sharing contracts, one operated and two non-operated. In December 2012, the Company agreed to sell the Indonesian properties to a third party. The sale closed in early 2013.

Other  Anadarko also has exploration projects in other overseas, new-venture areas including Colombia, Guyana, Morocco, Tunisia, and South Africa.

Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in billion cubic feet (Bcf), at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (MMBbls) for oil, condensate, and NGLs. Total volumes are presented in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural-gas reserves volumes.

Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria, Ghana, and China, which by country and in total represents less than 15% of the Company’s total proved reserves.

 

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Summary of Proved Reserves

 

    Natural Gas
(Bcf)
    Oil and
Condensate
(MMBbls)
    NGLs
(MMBbls)
    Total
(MMBOE)
 

December 31, 2012

       

Proved

       

Developed

       

United States

    6,445       318       283       1,675  

International

          208             208  

Undeveloped

       

United States

    1,884       193       110       617  

International

          48       12       60  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total proved

    8,329       767       405       2,560  
 

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2011

       

Proved

       

Developed

       

United States

    6,113       352       267       1,638  

International

          173             173  

Undeveloped

       

United States

    2,252       184       94       653  

International

          62       13       75  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total proved

    8,365       771       374       2,539  
 

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2010

       

Proved

       

Developed

       

United States

    5,982       303       222       1,523  

International

          150             150  

Undeveloped

       

United States

    2,135       195       85       635  

International

          101       13       114  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total proved

    8,117       749       320       2,422  
 

 

 

   

 

 

   

 

 

   

 

 

 

The Company’s year-end 2012 product mix for proved reserves was 54% natural gas, 30% oil and condensate, and 16% NGLs; compared to a year-end 2011 product mix of 55% natural gas, 30% oil and condensate, and 15% NGLs; and a year-end 2010 product mix of 56% natural gas, 31% oil and condensate, and 13% NGLs.

The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2012, 2011, and 2010, and changes in proved reserves during the last three years are presented in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K.

The Company has not filed information with a federal authority or agency with respect to its estimated total proved reserves at December 31, 2012. Annually, Anadarko reports gross proved reserves for U.S.-operated properties to the U.S. Department of Energy. These reported reserves are derived from the same database used to estimate and report proved reserves in this Form 10-K.

 

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Also presented in the Supplemental Information are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. See Operating Results and Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.

Changes in PUDs  Revisions of prior estimates include updates to prior PUDs, the addition of new PUDs associated with current development plans, the transfer of PUDs to unproved categories due to development plan changes, and the impact of changes in economic conditions, including lower commodity prices. These PUD changes reflect Anadarko’s ongoing evaluation of its asset portfolio and current-year changes to development plans. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years unless specific circumstances warrant a longer development time horizon. Significant changes to PUDs occurring during 2012 are summarized in the table below:

 

MMBOE

 

PUDs at January 1, 2012

    728  

Revisions of prior estimates

    102  

Extensions, discoveries, and other additions

    37  

Conversion to developed

    (171

Purchases

    3  

Sales

    (22
 

 

 

 

PUDs at December 31, 2012

            677  
 

 

 

 

PUD Conversion  In 2012, the Company converted 171 MMBOE, or 23% of total year-end 2011 PUDs to developed status. Approximately 79% of PUD conversions occurred in onshore U.S. assets, 15% in international assets, and the remaining 6% in Gulf of Mexico assets.

The majority of the onshore U.S. PUD conversions, approximately 133 MMBOE, occurred as a result of development activities in the Rockies and the Southern and Appalachia Regions. The remaining onshore U.S. PUD conversions were a result of development activity in Alaska. International PUD conversions, approximately 25 MMBOE, were primarily associated with ongoing development of the El Merk project located in Block 208 of the Berkine basin in Algeria where initial production is expected to occur in the first quarter of 2013. The Gulf of Mexico PUD conversions, approximately 11 MMBOE, were associated with development of the Nansen field.

Anadarko spent $1.0 billion to develop PUDs in 2012, of which approximately 69% related to domestic development programs in the Rockies and the Southern and Appalachia Regions, 28% to development of international projects, and the remaining 3% to Alaska and Gulf of Mexico development projects.

In 2011, the Company converted 171 MMBOE, or 23% of the total year-end 2010 PUDs to developed status. Approximately 58% of PUD conversions occurred in onshore U.S. assets, 26% in international assets, and the remaining 16% in Gulf of Mexico assets. Anadarko spent $900 million on PUD development in 2011. Approximately 68% of total 2011 PUD-development capital related to domestic development programs in the Rockies and the Southern and Appalachia Regions. Approximately 12% related to the development of the Caesar/Tonga and Lucius projects in the Gulf of Mexico, and 10% related to development of the El Merk project in Algeria. The remaining 10% of 2011 PUD-development spending was associated with Alaska and other international development projects.

 

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Development Plans  The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Typically, onshore U.S. PUDs are converted to developed reserves within five years of the initial proved reserves booking, but projects such as EOR, arctic development, deepwater development, and international programs may take longer. All of the Company’s onshore U.S. PUDs at December 31, 2012, were scheduled to be developed within five years, with the exception of the Salt Creek EOR project, the annual development of which is limited by CO2 supply contract terms and the amount of work that can be physically completed.

At December 31, 2012, the Company had 91 MMBOE of pre-2008 PUDs that remain undeveloped five years or more after initial disclosure as PUDs. Approximately 40% of these PUDs are associated with the El Merk development project and are being developed according to an Algerian government-approved plan. Site preparation was initiated in 2008 and construction of the El Merk central processing facility is progressing, with commissioning of the first train in its final stages. At year-end 2012, 89 wells of the Reservoir Development Plan’s estimated 119 total wells have been drilled. First oil production from the El Merk fields is expected to occur in the first quarter of 2013.

Another 33% of the Company’s pre-2008 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $74 million per year to develop various phases of the Salt Creek EOR project and will continue significant spending levels in the future to complete the development. In 2012, the Company demonstrated its continued interest in developing the project by entering into a carried-interest arrangement with a third party to fund $400 million of the costs associated with ongoing development activities.

All remaining pre-2008 PUDs are associated with Gulf of Mexico opportunities where longer development times are primarily a result of moratorium-related delays. The Company expects to develop its pre-2008 Gulf of Mexico PUDs over the next three years.

Technologies Used in Proved Reserves Estimation  The Company’s 2012 proved reserves additions were based on estimates generated through the integration of relevant geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

Internal Controls over Reserves Estimation  Anadarko’s estimates of proved reserves and associated future net cash flows were made solely by the Company’s engineers and are the responsibility of management. The Company requires that reserves estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers’ standards. The QREs are assigned to specific assets within the Company’s regions. The QREs interact with engineering, land, and geoscience personnel to obtain the necessary data for projecting future production, net cash flows, and ultimate recoverable reserves. Management within each region approves the QREs’ reserves estimates. All QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group (CRG).

 

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Index to Financial Statements

The CRG ensures confidence in the Company’s reserves estimates by maintaining internal policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance. Compliance with the SEC reserves guidelines is the primary responsibility of Anadarko’s CRG.

The CRG is managed through the Company’s finance department, which is separate from its operating regions, and is responsible for overseeing internal reserves reviews and approving the Company’s reserves estimates. The Director–Reserves Administration and the Corporate Reserves Manager manage the CRG and report to the Director–Corporate Planning. The Director–Corporate Planning reports to the Company’s Senior Vice President, Finance and Chief Financial Officer, who in turn reports to the President and Chief Executive Officer. The Audit Committee of the Company’s Board of Directors meets with management, members of the CRG, and the Company’s independent petroleum consultants, Miller and Lents, Ltd. (M&L), to discuss the results of procedures and methods reviews as discussed below, as well as other matters and policies related to reserves.

The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 26 years of experience in the oil and gas industry, including over 12 years as either a reserves estimator or manager. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserves training, and asset evaluation and management. The principal engineer is a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers, where he has been a member for over 26 years. In addition, the principal engineer is an active participant in industry reserves seminars and professional industry groups.

Third-Party Procedures and Methods Reviews  M&L reviewed the procedures and methods used by Anadarko’s staff in preparing its internal estimates of proved reserves and future net cash flows at December 31, 2012. The purpose of the review was to determine that the procedures and methods used by Anadarko to estimate its proved reserves are effective and in accordance with the definitions contained in SEC regulations. The procedures and methods review by M&L was a limited review of Anadarko’s procedures and methods and does not constitute a complete review, audit, independent estimate, or confirmation of the reasonableness of Anadarko’s estimates of proved reserves and future net cash flows.

The review consisted of 17 fields which included major assets in the United States and Africa, and encompassed approximately 87% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2012. In each review, Anadarko’s technical staff presented M&L with an overview of the data, methods, and assumptions used in estimating its reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures, and relevant economic criteria.

Management’s intent in retaining M&L to review its procedures and methods is to provide objective third-party input on the Company’s procedures and methods and to gather industry information applicable to reserves estimation and reporting processes.

 

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Sales Volumes, Prices, and Production Costs

The Company’s sales volumes were 268 MMBOE for 2012, 248 MMBOE for 2011, and 235 MMBOE for 2010. Production costs are costs to operate and maintain the Company’s wells and related equipment and include the cost of labor, well service and repair, location maintenance, power and fuel, transportation, other taxes, and production-related general and administrative costs. Additional information on volumes, prices, and production costs is contained in Financial Results under Item 7 of this Form 10-K. Additional detail regarding production costs is contained in the Supplemental Information under Item 8 of this Form 10-K. Information on major customers is contained in Note 21—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The following table provides the Company’s annual sales volumes, average sales prices, and average production costs per BOE for each of the last three years:

 

                                                                                                                                                       
    Sales Volumes     Average Sales Prices (1)     Average
Production
Costs (2)
(Per BOE)
 
    Natural
Gas
(Bcf)
    Oil and
Condensate
(MMBbls)
    NGLs
(MMBbls)
    Barrels of
Oil
Equivalent
(MMBOE)
    Natural
Gas
(Per Mcf)
    Oil and
Condensate
(Per Bbl)
    NGLs
(Per Bbl)
   

2012

               

United States

               

Greater Natural Buttes

    163       1       5       33     $     2.26     $   81.34     $   40.43     $     8.75  

Wattenberg

    95       12       5       33       3.00       92.16       40.72       8.05  

Other United States

    655       42       20       171       2.73       99.36       40.37       8.76  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total United States

    913       55       30       237       2.68       97.46       40.44       8.66  
 

 

 

   

 

 

   

 

 

   

 

 

         

International

           31              31              111.11              10.89  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total

    913       86       30       268       2.68       102.35       40.44       8.92  
 

 

 

   

 

 

   

 

 

   

 

 

         

2011

               

United States

               

Greater Natural Buttes

    135       1       4       27     $ 3.58     $ 84.13     $ 51.50     $ 9.48  

Wattenberg

    79       9       5       27       4.17       91.91       53.85       7.58  

Other United States

    638       38       18       163       3.90       99.28       54.55       9.80  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total United States

    852       48       27       217       3.87       97.70       53.95       9.50  
 

 

 

   

 

 

   

 

 

   

 

 

         

International

           31              31              109.20              9.98  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total

    852       79       27       248       3.87       102.24       53.95       9.55  
 

 

 

   

 

 

   

 

 

   

 

 

         

2010

               

United States

               

Greater Natural Buttes

    107       1       4       23     $ 3.92     $ 66.61     $ 40.31     $ 9.56  

Wattenberg

    74       7       3       22       4.28       76.07       43.44       6.79  

Other United States

    648       40       16       164       4.14       74.91       43.69       8.82  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total United States

    829       48       23       209       4.12       74.96       43.07       8.68  
 

 

 

   

 

 

   

 

 

   

 

 

         

International

           26              26              78.52              7.56  
 

 

 

   

 

 

   

 

 

   

 

 

         

Total

    829       74       23       235       4.12       76.22       43.07       8.56  
 

 

 

   

 

 

   

 

 

   

 

 

         

 

Bcf—billion cubic feet

Mcf—thousand cubic feet

Bbl—barrel

 

(1) 

Excludes the impact of commodity derivatives.

 

(2) 

Excludes ad valorem and severance taxes.

 

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Delivery Commitments

The Company sells crude oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2012, Anadarko was contractually committed to deliver approximately 1,150 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates with approximately 45% of the Company’s current commitment to be delivered in 2013, and 70% by 2017. At December 31, 2012, Anadarko also was contractually committed to deliver approximately 10 MMBbls of crude oil to ports in Algeria and Ghana through 2013. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

Properties and Leases

The following schedule shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2012:

 

                                                                                                                                       
    Developed
Lease
    Undeveloped
Lease
    Fee Mineral     Total  
thousands of acres   Gross     Net     Gross     Net     Gross     Net     Gross     Net  

United States

               

Onshore

    5,081       3,098       5,556       2,592       10,285       8,438       20,922       14,128  

Offshore

    300       151       2,410       1,620                   2,710       1,771  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total United States

    5,381       3,249       7,966       4,212       10,285       8,438       23,632       15,899  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

International

    362       88       68,474       46,096                   68,836       46,184  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    5,743       3,337       76,440       50,308       10,285       8,438       92,468       62,083  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

At December 31, 2012, the Company had approximately 3 million net undeveloped lease acres scheduled to expire by December 31, 2013, if the Company does not establish production or take any other action to extend the terms. The Company plans to continue the terms of many of these licenses and concession areas through operational or administrative actions and does not expect a significant portion of the Company’s net acreage position to expire before such actions occur.

Drilling Program

The Company’s 2012 drilling program focused on proven and emerging oil and natural-gas basins in the United States (onshore and deepwater Gulf of Mexico) and various international locations. Exploration activity in 2012 consisted of 222 gross completed wells, which included 212 onshore U.S. wells, 1 offshore Gulf of Mexico well, and 9 international wells. Development activity in 2012 consisted of 1,390 gross completed wells, which included 1,379 onshore U.S. wells, 1 offshore Gulf of Mexico well, and 10 international wells.

 

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Drilling Statistics

The following table shows the number of oil and gas wells that completed drilling in each of the last three years:

 

                                                                                                                                                                              
    Net Exploratory     Net Development     Total  
    Productive     Dry Holes     Total     Productive     Dry Holes     Total    

2012

             

United States

    79.5       1.0             80.5       923.7       11.3           935.0        1,015.5  

International

    0.5       3.0       3.5       2.1             2.1       5.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    80.0       4.0       84.0       925.8       11.3       937.1       1,021.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2011

             

United States

    79.0       2.2       81.2       1,169.6       6.3       1,175.9       1,257.1  

International

    0.5       1.2       1.7       6.8       0.2       7.0       8.7  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    79.5       3.4       82.9       1,176.4       6.5       1,182.9       1,265.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2010

             

United States

    84.3       1.2       85.5       1,027.9       3.6       1,031.5       1,117.0  

International

          3.6       3.6       11.2             11.2       14.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    84.3       4.8       89.1       1,039.1       3.6       1,042.7       1,131.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion at December 31, 2012:

 

    Wells in the process
of drilling or
in active completion
    Wells suspended or
waiting on completion  (1)
 
    Exploration     Development     Exploration     Development  

United States

       

Gross

    12       90       178       658  

Net

    5.0       56.3       63.9       431.9  

International

       

Gross

    2       5       40       1  

Net

    0.7       1.1       13.8       0.1  

Total

       

Gross

    14       95       218       659  

Net

    5.7       57.4       77.7       432.0  

 

(1) 

Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

 

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Index to Financial Statements

Productive Wells

At December 31, 2012, the Company’s ownership interest in productive wells was as follows:

 

    Oil Wells (1)     Gas Wells (1)  

United States

   

Gross

    4,222       28,476  

Net

    3,094.2       17,851.6  

International

   

Gross

    347        

Net

    87.9        

Total

   

Gross

    4,569       28,476  

Net

    3,182.1       17,851.6  

 

(1)       Includes wells containing multiple completions as follows:

   

Gross

    401       2,609  

Net

    356.2       2,058.6  

MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in midstream (gathering, processing, treating, and transportation) assets to complement its operations in regions where the Company has oil and natural-gas production. Through ownership and operation of these facilities, the Company improves its ability to manage costs, controls the timing of bringing on new production, and enhances the value received for gathering, processing, treating, and transporting the Company’s production. Anadarko’s midstream business also provides services to third-party customers, including major and independent producers. Anadarko generates revenues from its midstream activities through a variety of agreements, including fixed-fee, percent-of-proceeds, and keep-whole agreements.

At the end of 2012, Anadarko had 31 gathering systems and 26 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2012, the Company’s midstream activity was concentrated in liquids-rich growth areas such as Greater Natural Buttes, Wattenberg, Delaware basin, and the Eagleford shale, as well as in the Marcellus shale dry-gas play. In 2013, the Company plans to continue midstream investments in these core areas along with further expansion in the Carthage area in East Texas.

Greater Natural Buttes  A second cryogenic processing train was put in service at the Chipeta processing complex in 2012, increasing aggregate cryogenic processing capacity to 550 MMcf/d and total processing capacity to 970 MMcf/d. The Company received Federal Energy Regulatory Commission approval to expand its wet-gas-gathering system to the Chipeta plant in 2012 and expects to begin transporting gas on the new lines in the first half of 2013.

Wattenberg  The Company is currently constructing the 300 MMcf/d Lancaster cryogenic processing plant, with expected completion in early 2014. The plant will support increasing production from horizontal drilling in the Niobrara development, helping to relieve processing constraints in the basin. Prior to the Lancaster plant completion, the Company plans to install interim refrigeration capacity of 180 MMcf/d that is expected to be fully deployed by mid-2013, allowing the Company’s production growth to continue throughout the year.

 

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Anadarko and joint-venture partners plan to build a 435-mile NGLs pipeline (Front Range Pipeline) with initial capacity of 150,000 Bbls/d and ability to expand the capacity to 230,000 Bbls/d. The pipeline will transport NGLs from Weld County, Colorado to Skellytown, Texas, where it will connect with other pipelines, including the Texas Express Pipeline (TEP). During 2011, Anadarko and its partners agreed to design and construct the TEP to originate from Skellytown, Texas and to extend approximately 580 miles to NGLs fractionation and storage facilities in Mont Belvieu, Texas. Initial capacity of the TEP will be approximately 280,000 Bbls/d that can be expanded to approximately 400,000 Bbls/d. Subject to regulatory approvals, the TEP is expected to be in service in the third quarter of 2013 and the Front Range Pipeline is expected to be in service in the fourth quarter of 2013. The Front Range Pipeline and TEP are expected to enhance the value of the Company’s production by providing additional NGLs takeaway capacity and access to the Gulf Coast NGLs market.

Permian  In the Delaware basin in West Texas, the Company expanded its midstream infrastructure for Bone Spring and Avalon production. The Avalon Express, a 200 MMcf/d high-pressure gas pipeline system, was placed in service in August 2012 and includes 40 MMcf/d of compression and treating capacity. Three central processing facilities were commissioned with a total liquids (oil and water) handling capacity of 42,000 Bbls/d. In the third quarter of 2012, a 25 MMcf/d refrigeration plant was placed in service to process Bone Spring natural-gas production. A second-phase 100 MMcf/d cryogenic plant was placed in service in January 2013 to maximize Bone Spring liquids recoveries.

Eagleford  In the Eagleford shale in South Texas, gas-gathering capacity was expanded from 225 MMcf/d in 2011 to 350 MMcf/d in 2012 and crude-oil gathering capacity remained flat at 45,000 Bbls/d. The system is expected to expand to 600 MMcf/d of gas gathering and 75,000 Bbls/d of crude-oil gathering capacity by the end of 2013. Construction is underway for a new Company-operated cryogenic processing plant (Brasada) in the Eagleford shale with capacity of 200 MMcf/d, including a 15,000 Bbls/d condensate stabilization plant. The Company expects the Brasada plant to be operational in the second quarter of 2013. The Company also has secured approximately 38,000 Bbls/d of transportation and fractionation capacity on a new 200-mile raw-mix pipeline from Cotulla, Texas to Mont Belvieu, Texas. The Company has the right to expand to 75,000 Bbls/d of transportation and fractionation capacity on this pipeline.

Marcellus  In the Marcellus shale in Pennsylvania, Anadarko’s gas-gathering capacity increased from 500 MMcf/d in 2011 to over 1,500 MMcf/d in 2012. The Company commissioned the 24-inch Seely trunkline in the second quarter of 2012 and the 24-inch Warrensville trunkline in the fourth quarter of 2012. The Company also commissioned over 10,000 horsepower of compression in 2012.

East Texas/Haynesville  In the Carthage area of East Texas, Anadarko entered into a firm processing agreement with a third party for 120 MMcf/d of processing capacity at a cryogenic processing plant that was placed in service in late 2012. The plant supports the Company’s growing liquids-rich production in the Haynesville shale and Cotton Valley formations in East Texas and Louisiana.

Western Gas Partners, LP (WES), a consolidated subsidiary of Anadarko, is a publicly traded limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES’s general partner is owned by Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in WES, as well as WES’s general partner. In December 2012, WGP completed its initial public offering of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit. At December 31, 2012, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest. WGP’s ownership interest in WES consisted of a 46.2% limited partner interest, the entire 2.0% general partner interest, and all of the WES incentive distribution rights.

 

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Index to Financial Statements

The following table provides information regarding the Company’s midstream assets by geographic regions:

 

Area

 

Asset Type

  Miles of
Gathering
Pipelines
    Total
Horsepower
    2012
Average
Throughput
(MMcf/d)
 

Rocky Mountains

  Gathering, processing, and treating     10,000       1,150,200       3,800  

Mid-Continent and other

  Gathering     2,500       114,000       500  

Texas

  Gathering and treating     2,800       307,600       900  
   

 

 

   

 

 

   

 

 

 

Total

      15,300       1,571,800       5,200  
   

 

 

   

 

 

   

 

 

 

MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s natural-gas, crude-oil, condensate, and NGLs sales. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. The Company’s sales of natural gas, crude oil, condensate, and NGLs are generally made at market prices for those products at the time of sale. The Company also purchases natural gas, crude oil, condensate, and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes so that the Company is positioned to utilize transportation and storage capacity fully, attract creditworthy customers, facilitate efforts to maximize prices received, and minimize balancing issues with customers and pipelines during operational disruptions.

The Company sells natural gas under a variety of contracts including indexed, fixed-price, and cost-escalation-based agreements. The Company also engages in limited trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, crude-oil, and NGLs commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell natural gas, crude oil, and NGLs in the future for specific prices) that is offset by the Company’s natural long position as a producer (reflecting ownership of underlying natural-gas and crude-oil reserves). See Commodity Price Risk under Item 7A of this Form 10-K.

Natural Gas  Anadarko markets its natural-gas production to maximize value and to reduce the inherent risks of physical commodity markets. Anadarko’s marketing segment offers supply-assurance and limited risk-management services at competitive prices, as well as other services that are tailored to its customers’ needs. The Company may also receive a service fee related to the level of reliability and service required by the customer.

The Company controls natural-gas firm-transportation capacity that ensures access to downstream markets, which enables the Company to maximize its natural-gas production. This transportation capacity also provides the opportunity to capture incremental value when price differentials between physical locations exist. The Company stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical-delivery or financial derivative instruments) to sell stored natural gas at a fixed price.

 

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Index to Financial Statements

Crude Oil, Condensate, and NGLs  Anadarko’s crude-oil, condensate, and NGLs revenues are derived from production in the United States, Algeria, China, and Ghana. Most of the Company’s U.S. crude-oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality, and transportation. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD) Blend to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the market for the heavy fuel oil blend stock. Oil from Ghana is sold by tanker as Jubilee Crude Oil to customers around the world. Jubilee Crude Oil is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. The Company also purchases and sells third-party-produced crude oil, condensate, and NGLs, and utilizes contracted NGLs storage facilities to capture market opportunities and reduce fractionation and downstream infrastructure disruptions.

COMPETITION

The oil and gas business is highly competitive in the exploration for and acquisition of reserves and in the gathering and marketing of oil and gas production. The Company’s competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers.

SEGMENT INFORMATION

For additional information on operations by segment, see Note 21—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

For additional information on risk associated with international operations, see Risk Factors under Item 1A of this Form 10-K.

EMPLOYEES

The Company had approximately 5,200 employees at December 31,  2012.

REGULATORY MATTERS, ENVIRONMENTAL, AND ADDITIONAL FACTORS AFFECTING BUSINESS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, federal, regional, state, and local environmental and occupational health and safety laws and regulations. These laws and regulations pertain to the discharge of materials into the environment; the generating, handling, and disposal of materials (including solid and hazardous wastes); the workplace health and safety of employees; or otherwise relating to the prevention, mitigation, or remediation of pollution, or the protection of natural resources, wildlife, or the environment. The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:

 

   

the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements

 

   

the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), which regulates discharges of pollutants from facilities to state and federal waters

 

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Index to Financial Statements
   

the U.S. Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to strict liability for removal costs and damages arising from an oil spill in waters of the United States

 

   

U.S. Department of the Interior (DOI) regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages

 

   

the Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur

 

   

the U.S. Resource Conservation and Recovery Act, which governs the treatment, storage, and disposal of solid wastes, including hazardous wastes

 

   

the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources

 

   

the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and response departments

 

   

the U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures

 

   

the National Environmental Policy Act, which requires federal agencies, including the DOI, to evaluate major agency actions having the potential to impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment

 

   

the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

 

   

the Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and which may require the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

 

   

the Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

 

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Index to Financial Statements

These laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Compliance with these laws and regulations also, in most cases, requires new or amended permits that may contain new or more stringent technological standards or limits on emissions, discharges, disposals, or other releases in association with new or modified operations. Application for these permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with public notice and comment periods required prior to the issuance or amendment of a permit as well as the agency’s processing of an application. Many of the delays associated with the permitting process are beyond the control of the Company.

Many states and foreign countries where the Company operates also have, or are developing, similar environmental laws, regulations, or analogous controls governing many of these same types of activities. While the legal requirements may be similar in form, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the development of a project or substantially increase the cost of doing business.

Anadarko is also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations.

Federal and state occupational safety and health laws require the Company to organize information about materials, some of which may be hazardous or toxic, that are used, released, stored, or produced in Anadarko’s operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens. The Company is also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.

There have been several regulatory and governmental initiatives related to the hydraulic-fracturing process, which could have an adverse impact on our completion or production activities. The U.S. Environmental Protection Agency (EPA) has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic-fracturing practices involving diesel notwithstanding the existence of current oil and gas regulations adopted at the state level. Moreover, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a final draft report expected to be available for public comment and peer review by 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities for shale gas by 2014. Certain other governmental reviews have been recently conducted or are underway that focus on environmental aspects of hydraulic-fracturing practices, including evaluations by the U.S. Department of Energy and the DOI, and coordination of an administration-wide review of these practices by the White House Council on Environmental Quality. Congress has from time to time considered bills that would regulate hydraulic fracturing and/or require public disclosure of chemicals used in the hydraulic-fracturing process. A number of states, including states in which we operate, have adopted or are considering legal requirements that could impose more stringent permitting, public disclosure, and well-construction requirements on hydraulic-fracturing activities.

 

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Index to Financial Statements

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as new standards, such as air emission standards and water quality standards, continue to evolve. For example, on August 16, 2012, the EPA published final rules under the federal Clean Air Act that subject oil and natural-gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from fractured and refractured gas wells for which well-completion operations are conducted. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012, and from pneumatic controllers and storage vessels, effective October 15, 2013. In addition, environmental laws and regulations, including those that may arise to address concerns about global climate change and the threat of adverse impacts to groundwater arising from hydraulic-fracturing activities, are expected to continue to have an increasing impact on the Company’s operations in the United States and in other countries in which Anadarko operates. Notable areas of potential impacts include air emission monitoring, compliance, mitigation, and remediation obligations in the United States.

The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events. OPA imposes joint and several liability on the responsible parties for all cleanup and response costs, natural resource damages, and other damages such as lost revenues, damages to real or personal property, damages to subsistence users of natural resources, and lost profits and earning capacity. While OPA requires that a responsible party pay for all cleanup and response costs, it currently limits liability for damages to $75 million, exclusive of response and remediation expenses (for which there is no cap), except in cases of gross negligence, willful misconduct, or the violation of an applicable federal safety, construction, or operating regulation. The federal government may take legislative or other action to increase or eliminate, perhaps even retroactively, the liability cap. As for damages to natural resources, the government may recover damages for injury to, loss of, destruction of, or loss of use of natural resources which may include the costs to repair, replace, or restore those or like resources. The CWA governs discharges into waters of the United States and provides for penalties in the event of unauthorized discharges into those waters. Under the CWA, these include, among other penalties, civil penalties that may be assessed in an amount up to $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties that may be sought by the EPA are increased to not more than $4,300 per barrel of oil discharged.

As of the date of filing this Form 10-K with the SEC, no penalties or fines have been assessed by the federal government against the Company under OPA, CWA, and other similar local, state and federal environmental legislation related to the Deepwater Horizon events. However, in December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana, against several parties, including the Company, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. In October 2011, the Company and BP Exploration & Production Inc. (BP) entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement), pursuant to which BP has fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events and related damage claims arising under OPA. Under the Settlement Agreement, BP does not indemnify the Company against penalties or fines that may be assessed against the Company as a result of the Deepwater Horizon events, including for example, penalties or fines under the CWA. For additional information, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements

The Company has made and will continue to make operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. These are necessary business costs in the Company’s operations and in the oil and natural-gas industry. Although the Company is not fully insured against all environmental and occupational health and safety risks, and the Company’s insurance does not cover any penalties or fines that may be issued by a governmental authority, it maintains insurance coverage that it believes is sufficient based on the Company’s assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental and occupational health and safety laws and regulations, as well as claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities, including administrative, civil, and criminal penalties, to Anadarko. The Company believes that it is in material compliance with existing environmental and occupational health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial position, results of operations, or cash flows, but new or more stringently applied existing laws and regulations could increase the cost of doing business, and such increases could be material.

Oil Spill-Response Plan

Domestically, the Company is required to comply with the Bureau of Safety and Environmental Enforcement (BSEE) regulations, which require every owner or operator of a U.S. offshore lease to prepare and submit for approval an oil spill-response plan prior to conducting any offshore operations. The submitted plan is required to provide a detailed description of actions to be taken in the event of a spill, identify contracted spill-response equipment, materials and trained personnel, and stipulate the time necessary to deploy identified resources in the event of a spill. The Company has filed the information that describes the Company’s ability to deploy surface and subsea containment resources to adequately and promptly respond to a blowout or other loss of well control. The BSEE regulations may be amended, resulting in changes to the amount and type of spill-response resources to which an owner or operator must maintain ready access. Accordingly, resources available to the Company may change in order to satisfy any new regulatory requirements, or to adapt to changes in the Company’s operations.

Anadarko has in place and maintains both Regional (Central and Western Gulf of Mexico) and Sub-Regional (Eastern Gulf of Mexico) Oil Spill-Response Plans (Plans) for the Company’s Gulf of Mexico operations. The Plans detail procedures for a rapid and effective response to spill events that may occur as a result of Anadarko’s operations. The Plans are reviewed at least annually and updated as necessary. Drills are conducted at least annually to test the effectiveness of the Plans and include the participation of spill-response contractors, representatives of Clean Gulf Associates (CGA, a not-for-profit association of production and pipeline companies operating in the Gulf of Mexico), and representatives of relevant governmental agencies. The Plans must be approved by the BSEE.

As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in CGA, and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico.

CGA equipment includes one High Volume Open Sea Skimmer System (HOSS) barge, one 95-foot skimming vessel, four 46-foot skimming vessels, four 56-foot skimming vessels, three Marco skimmers, and two Egmopol skimmers. Additional available equipment includes the following: fast response units, rope mop, barges, skimming arms, skim packages, and tanks. In addition, auto boom, beach boom, and fire boom are currently available through CGA. CGA also has a stockpile of Corexit 9500 dispersant spray system through Airborne Support Inc. (ASI), a wildlife rehabilitation trailer, and bird scare guns. CGA currently has one X-band radar installed on the HOSS barge. CGA has ordered one 95–foot fast response vessel and is scheduled to receive delivery on or about the end of the second quarter of 2014.

 

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Index to Financial Statements

CGA has executed a support contract with T&T Marine to coordinate bareboat charters and provides for expanded response support. T&T Marine is responsible for inspecting, maintaining, storing, and calling out CGA equipment. T&T Marine has positioned CGA’s equipment and materials in a ready state at various staging areas around the Gulf of Mexico.

T&T Marine also handles the maintenance and mobilization of CGA non-marine equipment. T&T Marine has service contracts in place with domestic environmental contractors as well as with other companies that provide support services during the execution of spill-response activities. In the event of a spill, T&T Marine will activate these contracts as necessary to provide additional resources or support services requested by CGA. In addition, CGA maintains a service contract with ASI, which provides aircraft and dispersant capabilities for CGA member companies.

Anadarko is also a member of the Marine Preservation Association, which provides full access to the Marine Spill Response Corporation (MSRC) cooperative including the Deep Blue enhanced Gulf of Mexico Response capability. In the event of a spill, MSRC stands ready to mobilize all of its equipment and materials. MSRC has a fleet of 15 dedicated Responder Class Oil Spill-Response Vessels (OSRVs), designed and built specifically to recover spilled oil. Each OSRV is approximately 210 feet long, has temporary storage for recovered oil, and has the ability to separate oil and water aboard the vessels using two oil-water separation systems. To enable the OSRV to sustain cleanup operations, recovered oil can be transferred into other vessels or barges.

MSRC has equipment housed for the Atlantic Region, the Gulf of Mexico Region, the California Region, and the Pacific Northwest Region. The Gulf of Mexico Region has a total of 61 skimmers with an Effective Daily Recovery Capacity (EDRC) of approximately 562,408 barrels. The California Region has approximately 278,330 barrels EDRC and the Pacific Northwest Region has approximately 335,253 barrels EDRC. Additional available equipment includes the following: OSRVs, fast response vessels, barges, storage bladders, work boats, ocean boom, and dispersant.

The Company has also entered into a contractual commitment to access subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. Marine Well Containment Company (MWCC) is open to all oil and gas operators in the Gulf of Mexico and provides members access to oil spill-response equipment and services on a per-well fee basis. Anadarko has an employee representative on the executive committee of MWCC and this employee currently serves as its Chair. MWCC members have access to an interim containment system that includes a 15-kpsi capping stack and dispersant capability. The interim containment system is engineered to operate in deepwater depths of up to 10,000 feet, and has the capacity to contain 60 thousand barrels per day (MBbls/d) of liquids and flare 120 MMcf/d of natural gas. The DOI has reviewed the functional specifications of the MWCC interim containment system, and DOI input was included in the final specifications.

MWCC members also expect to have access to an expanded containment system that is planned for use in deepwater depths of up to 10,000 feet with containment capacity of 100 MBbls/d of liquids and flare capability for 200 MMcf/d of natural gas. The expanded system is planned to include a 15-kpsi subsea containment assembly with three rams stack, dedicated capture vessels, and a dispersant injection system. The expanded containment system may be further expanded with additional capture vessels, modified tankers, drill ships, and extended well-test vessels, all of which may process, store, and offload oil to shuttle tankers, which may then take the oil to shore for further processing. This expanded containment system is currently scheduled for delivery by mid-2013.

 

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Anadarko retains geospatial and satellite imagery services through the MDA Corporation (MDA) to provide coverage over the Company’s Gulf of Mexico operations. MDA owns and maintains two radar satellite’s, RADARSAT-1 and RADARSAT-2, that provide all-weather surveillance and imagery available to assist in identifying areas of concern on the surface waters of the Gulf of Mexico. The Company has agreements with Waste Management, Inc. and Clean Harbors to assist in the proper disposal of contaminated and hazardous waste soil and debris. In addition, Anadarko has agreements with HDR Engineering, Inc. (HDR) for assistance with Subsea Dispersant applications. Staff members of HDR are recognized as worldwide experts in the proper use of dispersants in a subsea application, developing scientific methods for determining the proper injection, and monitoring of the dispersant while maintaining the environmental and ecosystem integrity and health. The Company also has agreements with TDI-Brooks International for its scientific research vessels to properly monitor the effectiveness of the dispersant application and the health of the ecosystem. The Company also has agreements with Scientific and Environmental Associates, Inc. (SEA) for assistance with surface-dispersant applications. SEA is a scientific support consulting firm providing subject matter experts, and is renowned for its expertise in surface-dispersion applications and efficacy monitoring.

Anadarko has emergency and oil spill-response plans in place for each of its exploration and operational activities around the globe. Each plan satisfies the requirements of relevant local or national authority, describes the actions the Company will take in the event of an incident, is subject to drills at least annually, and includes reference to external resources that may become necessary in the event of an incident. Included in these external resources is the Company’s contract with Oil Spill Response Limited (OSRL), a global emergency and oil spill-response organization headquartered in London. OSRL maintains specialized equipment in a ready state for deployment in the event such equipment is needed by one of its members. OSRL is mainly available for response internationally, but its equipment is registered with the U.S. Coast Guard for domestic use if needed.

OSRL has two Hercules aircraft, located in the United Kingdom and Singapore, available for dispersant application or equipment transport. The aircraft have a three-hour callback time. The Hercules can transport two to three pre-packaged equipment loads, or one Aerial Dispersant Delivery System (ADDS) Pack. OSRL has three ADDS Packs: one in the United Kingdom, one in Bahrain, and one in Singapore. If additional aircraft are needed, OSRL retains an aircraft broker so that an aircraft can be chartered. For international operations, the majority of equipment will be air freighted.

OSRL has a number of active recovery boom systems, and a range of booms that can be used for offshore, nearshore, or shoreline responses. Offshore boom is stored in the United Kingdom, Bahrain, and Singapore. Fireboom systems have been delivered and a team is trained to operate the system. A variety of nearshore boom exists for spill containment.

OSRL also provides a range of communications equipment, safety equipment, transfer pumps, dispersant application systems, temporary storage equipment, power packs and generators, small inflatable vessels, rigid inflatable boats, work boats, and Fast Response Vessels. Oleophilic, weir, and mechanical skimmers provide the ability to recover a range of oil types. OSRL also has a wide range of oiled wildlife equipment in conjunction with the Sea Alarm Foundation.

In addition to Anadarko’s membership in or access to CGA, MSRC, OSRL, and MWCC, the Company participates in industry-wide task forces, which are currently studying improvements in both gaining access to and controlling blowouts in subsea environments. Two such task forces are the Subsea Well Control and Containment Task Force, and the Oil Spill Task Force.

 

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TITLE TO PROPERTIES

As is customary in the oil and gas industry, only a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. Anadarko believes the title to its leasehold properties is good, defensible, and customary with practices in the oil and gas industry, subject to such exceptions that, in the opinion of legal counsel for the Company, do not materially detract from the use of such properties.

Leasehold properties owned by the Company are subject to royalty, overriding royalty, and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements, current taxes, development obligations under oil and gas leases and other encumbrances, easements, and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.

EXECUTIVE OFFICERS OF THE REGISTRANT

 

Name

  Age at
February 19,
2013
 

Position

James T. Hackett

  59   Executive Chairman

R. A. Walker

  55   President and Chief Executive Officer

Robert P. Daniels

  54   Senior Vice President, International and Deepwater Exploration

Robert G. Gwin

  49   Senior Vice President, Finance and Chief Financial Officer

Charles A. Meloy

  52   Senior Vice President, U.S. Onshore Exploration and Production

Robert D. Lawler

  46   Senior Vice President, International and Deepwater Operations

Robert K. Reeves

  55   Senior Vice President, General Counsel and Chief Administrative Officer

M. Cathy Douglas

  56   Vice President and Chief Accounting Officer

Mr. Hackett was named Executive Chairman of Anadarko effective May 2012. Prior to this position, he served as Chief Executive Officer and as a director of the Company from December 2003 and assumed the additional role of Chairman of the Board in January 2006. He also served as President from December 2003 to February 2010. Prior to joining Anadarko, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation following its merger with Ocean Energy, Inc. in April 2003. He served as President and Chief Executive Officer of Ocean Energy, Inc. from March 1999 to April 2003 and as Chairman of the Board from January 2000 to April 2003. He currently serves as a director of Fluor Corporation, Bunge Limited, Cameron International Corporation, and The Welch Foundation. Mr. Hackett served as director of Temple-Inland Inc. from 2000 to 2008 and as a director of Halliburton Company from 2008 to 2011.

Mr. Walker was named Chief Executive Officer and a director of Anadarko in May 2012, in addition to the role of President, which he assumed in February 2010. Mr. Walker previously served as Chief Operating Officer from March 2009 until his appointment as Chief Executive Officer. He also served as Senior Vice President, Finance and Chief Financial Officer from September 2005 to March 2009. Since August 2007, he also has served as director of Western Gas Holdings, LLC (WGH), the general partner of WES, and served as its Chairman of the Board from August 2007 to September 2009. Mr. Walker has served as a director of Western Gas Equity Holdings, LLC (WGEH), the general partner of WGP, since September 2012. Prior to joining Anadarko, Mr. Walker served as Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005. Mr. Walker served as a director of Temple-Inland Inc. from November 2008 to February 2012 and has served as a director of CenterPoint Energy, Inc. since April 2010.

 

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Mr. Daniels was named Senior Vice President, International and Deepwater Exploration in July 2012. Prior to this position, he served as Senior Vice President, Worldwide Exploration since December 2006 and served as Senior Vice President, Exploration and Production since May 2004. Prior to that position, he served as Vice President, Canada since July 2001. Mr. Daniels also served in various managerial roles in the Exploration Department for Anadarko Algeria Company, LLC. He has worked for the Company since 1985.

Mr. Gwin was named Senior Vice President, Finance and Chief Financial Officer in March 2009 and previously had served as Senior Vice President since March 2008. He also has served as Chairman of the Board of WGH since October 2009 and as a director since August 2007. Additionally, Mr. Gwin has served as Chairman of the Board of WGEH, the general partner of WGP, since September 2012, and served as President of WGH from August 2007 to September 2009 and as Chief Executive Officer of WGH from August 2007 to January 2010. He joined Anadarko in January 2006 as Vice President, Finance and Treasurer and served in that capacity until March 2008. He has served as a director of LyondellBasell Industries N.V. since May 2010.

Mr. Meloy was named Senior Vice President, U.S. Onshore Exploration and Production in July 2012. Prior to this position, he served as Senior Vice President, Worldwide Operations since December 2006 and served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee Corporation (Kerr-McGee) in August 2006. Prior to joining Anadarko, he served Kerr-McGee as Vice President of Exploration and Production from 2005 to 2006, Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005, Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004 and Vice President of Gulf of Mexico Deepwater from 2000 to 2002. Mr. Meloy has served as a director of WGH since February 2009 and as a director of WGEH since September 2012.

Mr. Lawler was named Senior Vice President, International and Deepwater Operations in July 2012. Prior to this position, he served as Vice President, Operations for the Southern and Appalachia Region in the U.S. onshore since March 2009 and International Operations since December 2011. Prior to that, Mr. Lawler served as Vice President, Corporate Planning since August 2008. Mr. Lawler has held a variety of positions with increasing responsibility within operations, business planning and analysis departments since the acquisition of Kerr-McGee in August 2006. He began his career in 1988 with Kerr-McGee.

Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007 and assumed the additional role of Chief Compliance Officer in July 2012. He also served as Corporate Secretary from February 2007 to August 2008. He previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He has served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, since October 2007, as a director of WGH since August 2007 and as a director of WGEH since September 2012.

Ms. Douglas was named Vice President and Chief Accounting Officer in November 2008 and served as Corporate Controller from September 2007 to March 2009. She served as Assistant Controller from July 2006 to September 2007. She also served as Director, Accounting, Policy and Coordination from October 2006 to September 2007 and Financial Reporting and Policy Manager from January 2003 to October 2006. Ms. Douglas joined Anadarko in 1979.

Officers of Anadarko are elected each year at the first meeting of the Board of Directors following the annual meeting of stockholders, the next of which is expected to occur on May 14, 2013, and hold office until their successors are duly elected and qualified. There are no family relationships between any directors or executive officers of Anadarko.

 

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Item 1A.  Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

 

   

the Company’s assumptions about the energy market

 

   

production levels

 

   

reserves levels

 

   

operating results

 

   

competitive conditions

 

   

technology

 

   

availability of capital resources, capital expenditures, and other contractual obligations

 

   

supply and demand for, the price of, and the commercializing and transporting of natural gas, crude oil, natural gas liquids (NGLs), and other products or services

 

   

volatility in the commodity-futures market

 

   

weather

 

   

inflation

 

   

availability of goods and services, including unexpected changes in costs

 

   

drilling risks

 

   

future processing volumes and pipeline throughput

 

   

general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business

 

   

inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects

 

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legislative or regulatory changes, including retroactive royalty or production tax regimes; hydraulic-fracturing regulation; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations

 

   

ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations

 

   

impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against the Company, for which it is not indemnified by BP

 

   

legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations, including those resulting from the Deepwater Horizon events

 

   

current and potential legal proceedings, or environmental or other obligations related to or arising from Tronox Incorporated (Tronox)

 

   

civil or political unrest or acts of terrorism in a region or country

 

   

creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties

 

   

volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity and interest-rate risk

 

   

the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings

 

   

disruptions in international crude oil cargo shipping activities

 

   

physical, digital, internal, and external security breaches

 

   

supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations

 

   

other factors discussed below and elsewhere in this Form 10-K, and in the Company’s other public filings, press releases, and discussions with Company management

We are, and in the future may become, involved in legal proceedings related to Tronox and, as a result, may incur substantial costs in connection with those proceedings.

In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. An adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

For additional information regarding the nature and status of these and other material legal proceedings, see Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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We may be subject to claims and liabilities relating to the Deepwater Horizon events that are not covered by BP’s indemnification obligations under our Settlement Agreement with BP, or that result in losses to the Company, notwithstanding BP’s indemnification against such losses, as a result of BP’s inability to satisfy its indemnification obligations under the Settlement Agreement and BPCNA’s and BP p.l.c.’s inability to satisfy their guarantees of BP’s indemnification obligations.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, NRD claims and assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BPCNA and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor.

Any failure or inability on the part of BP to satisfy its indemnification obligations under the Settlement Agreement, or on the part of BPCNA or BP p.l.c. to satisfy their respective guarantee obligations, could subject us to significant monetary liability beyond the terms of the Settlement Agreement, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. In November 2012, BP settled all criminal and securities claims brought by the United States against BP, with BP agreeing to pay $4.0 billion over five years to the U.S. Department of Justice with respect to the criminal claims and further agreeing to pay another $525 million over three years to the Securities and Exchange Commission (SEC) with respect to the securities claims. BP represents that it is prepared to vigorously defend itself against remaining civil claims. Furthermore, in certain instances we may be required to recognize a liability for amounts for which we are indemnified in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. Any such liability recognition without collection of the offsetting receivable could adversely impact our results of operations, our financial condition, and our ability to make borrowings.

Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The adverse resolution of any current or future proceeding related to the Deepwater Horizon events for which we are not indemnified by BP could subject us to significant monetary liability, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

 

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Oil, natural-gas, and NGLs prices are volatile. A substantial or extended decline in the price of these commodities could adversely affect our financial condition and results of operations.

Prices for oil, natural gas, and NGLs can fluctuate widely. Our revenues, operating results, and future growth rates are highly dependent on the prices we receive for our oil, natural gas, and NGLs. The markets for oil, natural gas, and NGLs have been volatile historically and may continue to be volatile in the future. For example, market prices for natural gas in the United States have declined substantially from 2008 price levels, and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas, and NGLs are beyond our control. These factors include, but are not limited to, the following:

 

   

domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs

 

   

volatile trading patterns in the commodity-futures markets

 

   

cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs

 

   

level of global crude-oil and natural-gas inventories

 

   

weather conditions

 

   

potential U.S. exports of liquefied natural gas

 

   

ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels

 

   

worldwide military and political environment, civil and political unrest in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or further acts of terrorism in the United States, or elsewhere

 

   

effect of worldwide energy conservation and environmental protection efforts

 

   

price and availability of alternative and competing fuels

 

   

price and level of foreign imports of oil, natural gas, and NGLs

 

   

domestic and foreign governmental regulations and taxes

 

   

proximity to, and capacity of, natural-gas pipelines and other transportation facilities

 

   

general economic conditions worldwide

 

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The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

 

   

adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations

 

   

reducing the amount of oil, natural gas, and NGLs that we can produce economically

 

   

causing us to delay or postpone some of our capital projects

 

   

reducing our revenues, operating income, or cash flows

 

   

reducing the amounts of our estimated proved oil and natural-gas reserves

 

   

reducing the carrying value of our oil and natural-gas properties

 

   

reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves

 

   

limiting our access to, or increasing the cost of, sources of capital, such as equity and long-term debt

Our domestic operations are subject to governmental risks that may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, regional, state, tribal, local, and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing, and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, regional, state, tribal, and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws and regulations, are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, from time to time, legislation has been proposed that could adversely affect our business, financial condition, results of operations, or cash flows related to the following:

 

   

Climate Change.    A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, the U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs.

 

   

Deficit Reduction or Tax Reform.    Congress may undertake significant deficit reduction or comprehensive tax reform in the coming year. Proposals include provisions that would, if enacted, (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) eliminate the manufacturing deduction for oil and gas qualified production activities, and (iii) eliminate the acceleration of depreciation for tangible property.

 

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Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an essential and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels with the public comment period expiring in August 2012. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and scope of such disclosure regulations. In May 2012, the Department of the Interior (DOI) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Certain states in which we operate, including Colorado, Pennsylvania, Louisiana, Texas, Ohio, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic-fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where we currently conduct operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements. These costs may be significant in nature, and we may experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

 

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There are also certain governmental reviews recently conducted or underway that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards for shale gas by 2014. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods and, in August 2011, issued a report on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale-gas development. Also, as discussed above, the DOI is pursuing regulations governing hydraulic fracturing on federal and Indian oil and gas leases. These studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

The additional deepwater drilling laws and regulations, both domestically and internationally, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related developments arising after the deepwater drilling moratorium in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), each agencies of the DOI, issued directives in May and July 2010 requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf (OCS) regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, but excluding workovers, completions, plugging and abandonment, or production, through November 30, 2010. In addition, the agencies issued a series of rules and Notices to Lessees and Operators (NTLs) imposing new and more stringent regulatory safety and performance requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. The federal government may issue further safety and environmental laws and regulations regarding operations in the Gulf of Mexico.

Compliance with these new and more stringent rules and regulations, uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, and oil spill-response plans, as a result of the new laws and regulations, and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts in the Gulf of Mexico. Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased costs and limit activities in certain areas of the Gulf of Mexico, or cause us to incur penalties, fines, or shut-in production at one or all of our facilities. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations in the Gulf of Mexico.

Other governments may also adopt safety, environmental or other laws and regulations that would adversely impact our offshore developments in other areas of the world, including offshore Brazil, New Zealand, Africa, and Southeast Asia. Additional U.S. or foreign government laws or regulations would likely increase the costs associated with the offshore operations of our drilling contractors. As a result, our drilling contractors may seek to pass increased operating costs to us through higher day-rate charges or through cost escalation provisions in existing contracts.

 

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In addition to increased governmental regulation, insurance costs may increase across the energy industry and certain insurance coverage may be subject to reduced availability or not available on economically reasonable terms, if at all. In particular, the events in the Gulf of Mexico relating to the Deepwater Horizon incident may make it increasingly difficult to obtain offshore property damage, well control, and similar insurance coverage. The potential increased costs and risks associated with offshore development may also result in certain current participants allocating resources away from offshore development and discourage potential new participants from undertaking offshore development activities. Accordingly, we may encounter increased difficulty identifying suitable partners willing to participate in our offshore drilling projects and prospects.

Further, the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite the Company’s oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident.

The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

The enactment of derivatives legislation could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished. Depending on the Company’s classification and the particular nature of its derivative activities, the Dodd-Frank Act and regulations may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. The Dodd-Frank Act and regulations may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less-creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

 

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Our debt and other financial commitments may limit our financial and operating flexibility.

Our total debt was $13.3 billion at December 31, 2012. We also have various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services and products. Our financial commitments could have important consequences to our business including, but not limited to, the following:

 

   

increasing our vulnerability to general adverse economic and industry conditions

 

   

limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt or to comply with any restrictive terms of our debt

 

   

limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate

 

   

placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments

Additionally, the credit agreement governing our senior secured revolving credit facility ($5.0 billion Facility) contains a number of covenants that impose operating and financial constraints on the Company, including restrictions on our ability to incur additional indebtedness, sell assets, and incur liens. Provisions of the $5.0 billion Facility also require us to maintain specified financial covenants as further described in Liquidity and Capital Resources under Item 7 of this Form 10-K. Our ability to meet such covenants may be affected by events beyond our control.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

At December 31, 2012, our debt was rated “BBB-” with a positive outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a stable outlook by Moody’s Investors Service (Moody’s). Although we are not aware of any current plans of S&P, Fitch, or Moody’s to lower their respective ratings on our debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If our credit rating were downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be much higher than our outstanding debt. In addition, a downgrade could affect the Company’s requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. See Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause the quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. The reserves information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, no reserves audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows depend on a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates. These factors and assumptions may include, but are not limited to, the following:

 

   

historical production from an area compared with production from similar producing areas

 

   

assumed effects of regulation by governmental agencies and court rulings

 

   

assumptions concerning future oil and natural-gas prices, future operating costs and capital expenditures

 

   

estimates of future severance and excise taxes, workover costs, and remedial costs

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on average 12-month sales prices using the average beginning-of-month price. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.

Failure to replace reserves may negatively affect our business.

Our future success depends on our ability to find, develop, or acquire additional oil and natural-gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities, acquire properties containing proved reserves, or both. We may be unable to find, develop, or acquire additional reserves on an economic basis. Furthermore, if oil and natural-gas prices increase, our costs for finding or acquiring additional reserves could also increase.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A portion of our leasehold acreage is currently undeveloped. Unless production in sufficient quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based on various factors: drilling results, oil and natural-gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

 

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Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.

During the last few years, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If economic recovery in the United States or abroad is prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs; affect our vendors’, suppliers’ and customers’ ability to continue operations; and ultimately adversely impact our results of operations, liquidity, and financial condition.

Our results of operations could be adversely affected by goodwill impairments.

As a result of mergers and acquisitions, we had approximately $5.5 billion of goodwill on our Consolidated Balance Sheet at December 31, 2012. Goodwill must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment. Goodwill is considered impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to an impairment of goodwill, such as the Company’s inability to replace the value of its depleting asset base, or other adverse events, such as lower sustained oil and natural-gas prices, which could reduce the fair value of the associated reporting unit. An impairment of goodwill could have a substantial negative effect on our profitability.

We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner, and feasibility of doing business.

Our operations and properties are subject to numerous federal, regional, state, tribal, local, and foreign laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

 

   

issuance of permits in connection with exploration, drilling, production, and midstream activities

 

   

protection of endangered species

 

   

amounts and types of emissions and discharges

 

   

generation, management, and disposition of waste materials

 

   

offshore oil and gas operations and decommissioning of abandoned facilities

 

   

reclamation and abandonment of wells and facility sites

 

   

remediation of contaminated sites

In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations. Future environmental laws and regulations, such as the restriction against emission of pollutants from previously unregulated activities or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. The cost of satisfying these requirements may have an adverse effect on our financial condition, results of operations, or cash flows or could result in limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce our reserves. For a description of certain environmental proceedings in which we are involved, see Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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We are vulnerable to risks associated with our offshore operations that could negatively impact our operations and financial results.

We conduct offshore operations in the Gulf of Mexico, Ghana, Mozambique, Brazil, China, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, New Zealand, and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas because we are vulnerable to certain unique risks associated with operating offshore, including those relating to the following:

 

   

hurricanes and other adverse weather conditions

 

   

oilfield service costs and availability

 

   

compliance with environmental and other laws and regulations

 

   

terrorist attacks, such as piracy

 

   

remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials

 

   

failure of equipment or facilities

In addition, we conduct some of our exploration in deep waters (greater than 1,000 feet) where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require significant time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production and, as a result, our reserves replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

We operate in foreign countries and are subject to political, economic, and other uncertainties.

Our operations outside the United States are based primarily in Algeria, Brazil, China, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, and Sierra Leone. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include the following, among other things:

 

   

loss of revenue, property, and equipment as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks

 

   

transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act, and other anti-corruption compliance laws and issues

 

   

increases in taxes and governmental royalties

 

   

unilateral renegotiation of contracts by governmental entities

 

   

redefinition of international boundaries or boundary disputes

 

   

difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations

 

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changes in laws and policies governing operations of foreign-based companies

 

   

foreign-exchange restrictions

 

   

international monetary fluctuations and changes in the relative value of the U.S. dollar as compared to the currencies of other countries in which we conduct business

For example, Ghana and Côte d’Ivoire are currently engaged in a dispute regarding the international maritime and land boundaries between the two countries. As a result, Côte d’Ivoire claims to be entitled to the maritime area which covers a portion of the Deepwater Tano Block where we are currently conducting exploration and appraisal activities. In the event Côte d’Ivoire is successful in its maritime border claims, our operations in the block could be materially impacted.

Outbreaks of civil and political unrest and acts of terrorism have occurred in several countries in Africa and the Middle East, including countries where we conduct operations, such as Algeria and Tunisia. As exhibited by the events in Tunisia, Egypt, and Libya, outbreaks of civil and political unrest have resulted in established governing bodies being overthrown. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired.

Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.

Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations, or cash flows.

Our commodity-price risk-management and trading activities may prevent us from fully benefiting from price increases and may expose us to other risks.

To the extent that we engage in commodity-price risk-management activities to protect our cash flows from commodity-price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our commodity-price risk-management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which the following occur:

 

   

our production is less than the hedged volumes

 

   

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement

 

   

the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements

 

   

a sudden unexpected event materially impacts oil and natural-gas prices

 

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Deterioration in the credit or equity markets could adversely affect us.

We have exposure to different counterparties. For example, we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time.

We are not insured against all of the operating risks to which our business is exposed.

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing, and transportation of oil and gas, including blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations, production facilities, and other property, as well as injury to persons. For protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, aviation liability, and worker’s compensation and employer’s liability. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, business interruption, war, terrorism, and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from development projects.

We are involved in several large development projects. Key factors that may affect the timing and outcome of such projects include the following:

 

   

project approvals by joint-venture partners

 

   

timely issuance of permits and licenses by governmental agencies

 

   

weather conditions

 

   

availability of personnel

 

   

civil and political environment of the country or region in which the project is located

 

   

manufacturing and delivery schedules of critical equipment

 

   

commercial arrangements for pipelines and related equipment to transport and market hydrocarbons

Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to large development projects and could have a material adverse effect on our results of operations.

 

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The oil and gas exploration and production industry is very competitive, and some of our exploration and production competitors have greater financial and other resources than we do.

The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Some of our competitors may have greater and more diverse resources on which to draw than we do. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, or qualified personnel. During these periods, the costs of rigs, equipment, supplies, and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

Our drilling activities may not be productive.

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural-gas reservoirs. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including the following:

 

   

unexpected drilling conditions

 

   

pressure or irregularities in formations

 

   

equipment failures or accidents

 

   

fires, explosions, blowouts, and surface cratering

 

   

marine risks such as capsizing, collisions, and hurricanes

 

   

difficulty identifying and retaining qualified personnel

 

   

title problems

 

   

other adverse weather conditions

 

   

shortages or delays in the delivery of equipment

Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to high-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.

 

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We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

Our ability to sell our gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation.

The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities and tanker transportation. If any pipelines or tankers become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport the natural gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.

Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.

In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

We may reduce or cease to pay dividends on our common stock.

We can provide no assurance that we will continue to pay dividends at the current rate or at all. The amount of cash dividends, if any, to be paid in the future will depend on actions taken by our Board of Directors, as well as, our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, future business prospects, expected liquidity needs, and other related matters that our Board of Directors deems relevant.

The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success.

The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team could have an adverse effect on our business. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers, and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

 

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Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

GENERAL  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

Item 4.  Mine Safety Disclosures

Not applicable.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MARKET INFORMATION, HOLDERS, AND DIVIDENDS

At January 31, 2013, there were approximately 12,800 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the market price of and dividends declared and paid on the Company’s common stock by quarter for 2012 and 2011:

 

                                                                   
    First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
 

2012

       

Market Price

       

High

  $ 88.70     $ 79.85     $ 76.63     $ 76.95  

Low

  $ 75.90     $ 56.42     $ 64.19     $ 65.82  

Dividends

  $ 0.09     $ 0.09     $ 0.09     $ 0.09  

2011

       

Market Price

       

High

  $ 84.00     $ 85.50     $ 85.25     $ 84.42  

Low

  $ 73.02     $ 68.67     $ 63.03     $ 57.11  

Dividends

  $ 0.09     $ 0.09     $ 0.09     $ 0.09  

The amount of future common stock dividends will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with its financial covenants, and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Liquidity and Capital Resources—Uses of Cash—Common Stock Dividends and Distributions to Noncontrolling Interest Owners under Item 7 of this Form 10-K.

 

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SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, 2012:

 

Plan Category

  (a)
Number of  securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
    (b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
    (c)
Number of  securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
 

Equity compensation plans approved by security holders

    9,356,783     $ 58.66       29,652,758  

Equity compensation plans not approved by security holders

                 
 

 

 

   

 

 

   

 

 

 

Total

    9,356,783     $ 58.66       29,652,758  
 

 

 

   

 

 

   

 

 

 

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of 2012:

 

Period

  Total
number of
shares
purchased (1)
    Average
price paid
per share
    Total number of
shares purchased
as part of publicly
announced plans
or programs
    Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
 

October 1-31

    725     $ 69.17          

November 1-30

    152,359     $ 70.90          

December 1-31

    966     $ 74.19          
 

 

 

     

 

 

   

 

 

 

Fourth Quarter 2012

    154,050     $ 70.91            $   
 

 

 

     

 

 

   

 

 

 

 

(1) 

During the fourth quarter of 2012, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

For additional information, see Note 15—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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PERFORMANCE GRAPH

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative five-year total return to stockholders of Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and a peer group of 11 companies. The companies included in the peer group are Apache Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; Pioneer Natural Resources Company; and Plains Exploration and Production Company.

Comparison of 5-Year Cumulative Total Return Among

Anadarko Petroleum Corporation, the S&P 500 Index,

and a Peer Group

 

LOGO

Copyright© 2013 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in the peer group on December 31, 2007, and its relative performance is tracked through December 31, 2012.

 

                                                                 
Fiscal Year Ended December 31       2007         2008         2009         2010         2011         2012  

Anadarko Petroleum Corporation

  $ 100.00     $ 59.08     $ 96.41     $ 118.37     $ 119.21     $ 116.63  

S&P 500

    100.00       63.00       79.67       91.67       93.61       108.59  

Peer Group

    100.00       69.66       81.71       100.68       107.25       109.37  

 

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Index to Financial Statements

Item 6.  Selected Financial Data

 

    Summary Financial Information (1)  
millions except per-share amounts   2012     2011     2010     2009     2008  

Sales Revenues

  $ 13,307     $ 13,882     $ 10,842     $ 8,210     $ 14,079  

Gains (Losses) on Divestitures and Other, net

    104       85       142       133       1,083  

Reversal of Accrual for DWRRA Dispute

                      657        
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues and Other

    13,411       13,967       10,984       9,000       15,162  

Algeria Exceptional Profits Tax Settlement

    (1,797                        

Deepwater Horizon Settlement and Related Costs

    18       3,930       15              

Operating Income (Loss)

    3,727       (1,870     1,769       377       5,601  

Income (Loss) from Continuing Operations

    2,445       (2,568     821       (103     3,220  

Income from Discontinued Operations, net of taxes

                            63  

Net Income (Loss) Attributable to Common Stockholders

    2,391       (2,649     761       (135     3,260  

Per Common Share (amounts attributable to common stockholders):

         

Income (Loss) from Continuing Operations—Basic

  $ 4.76     $ (5.32   $ 1.53     $ (0.28   $ 6.79  

Income (Loss) from Continuing Operations—Diluted

  $ 4.74     $ (5.32   $ 1.52     $ (0.28   $ 6.78  

Income from Discontinued Operations—Basic

  $     $     $     $     $ 0.13  

Income from Discontinued Operations—Diluted

  $     $     $     $     $ 0.13  

Net Income (Loss)—Basic

  $ 4.76     $ (5.32   $ 1.53     $ (0.28   $ 6.92  

Net Income (Loss)—Diluted

  $ 4.74     $ (5.32   $ 1.52     $ (0.28   $ 6.91  

Dividends

  $ 0.36     $ 0.36     $ 0.36     $ 0.36     $ 0.36  

Average Number of Common Shares Outstanding—Basic

    500       498       495       480       465  

Average Number of Common Shares Outstanding—Diluted

    502       498       497       480       466  

Cash Provided by Operating Activities—Continuing Operations

  $ 8,339     $ 2,505     $ 5,247     $ 3,926     $ 6,447  

Cash Provided by (Used in) Operating Activities—Discontinued Operations

                            (5

Net Cash Provided by Operating Activities

    8,339       2,505       5,247       3,926       6,442  

Capital Expenditures

  $ 7,311     $ 6,553     $ 5,169     $ 4,558     $ 4,881  

Current Portion of Long-term Debt

  $     $ 170     $ 291     $     $ 1,472  

Long-term Debt

    13,269       15,060       12,722       11,149       9,128  

Midstream Subsidiary Note Payable to a Related Party

                      1,599       1,739  

Total Debt

  $ 13,269     $ 15,230     $ 13,013     $ 12,748     $ 12,339  

Total Stockholders’ Equity

    20,629       18,105       20,684       19,928       18,795  

Total Assets

  $ 52,589     $ 51,779     $ 51,559     $ 50,123     $ 48,923  

Annual Sales Volumes:

         

Natural Gas (Bcf)

    913       852       829       809       750  

Oil and Condensate (MMBbls)

    86       79       74       68       67  

Natural Gas Liquids (MMBbls)

    30       27       23       17       14  

Total (MMBOE) (2)

    268       248       235       220       206  

Average Daily Sales Volumes:

         

Natural Gas (MMcf/d)

    2,495       2,334       2,272       2,217       2,049  

Oil and Condensate (MBbls/d)

    233       217       201       187       182  

Natural Gas Liquids (MBbls/d)

    83       74       63       47       39  

Total (MBOE/d)

    732       680       643       604       563  

Proved Reserves:

         

Natural-Gas Reserves (Tcf)

    8.3       8.4       8.1       7.8       8.1  

Oil and Condensate Reserves (MMBbls)

    767       771       749       733       709  

Natural-Gas Liquids Reserves (MMBbls)

    405       374       320       277       217  

Total Proved Reserves (MMBOE)

    2,560       2,539       2,422       2,304       2,277  

Number of Employees

    5,200       4,800       4,400       4,300       4,300  
(1) 

Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.

(2) 

Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.

 

Table of Measures

   

Bcf—Billion cubic feet

 

MBbls/d—Thousand barrels per day

MMBbls—Million barrels

 

MBOE/d—Thousand barrels of oil equivalent per day

MMBOE—Million barrels of oil equivalent

 

Tcf—Trillion cubic feet

MMcf/d—Million cubic feet per day

 

 

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko met or exceeded its key operational objectives in 2012. The Company increased sales volumes by approximately 8% over 2011 and added 370 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its offshore exploration and appraisal drilling success with an approximate 67% success rate for wells completed in 2012. Anadarko fully repaid $2.5 billion of borrowings under the Company’s five-year $5.0 billion senior secured revolving credit facility ($5.0 billion Facility) with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute. The Company ended 2012 with $2.5 billion cash on hand, availability of the $5.0 billion Facility, and access to credit and capital markets as needed. Management believes that the Company is positioned to satisfy its operational objectives and capital commitments with cash on hand, available borrowing capacity, and cash flows from operations.

Mission and Strategy

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:

 

   

explore in high-potential, proven basins

 

   

identify and commercialize resources

 

   

employ a global business development approach

 

   

ensure financial discipline and flexibility

Exploring in high-potential, proven, and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing its future resource potential, while providing the flexibility to mitigate risk by monetizing discoveries.

Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient, predictable, and repeatable development opportunities which, in turn, positions the Company for consistent growth at competitive rates.

Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.

A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investing in its businesses to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic growth opportunities.

 

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Significant 2012 operating and financial activities include the following:

Overall

 

   

Anadarko’s total-year sales volumes were 732 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over 2011.

 

   

Anadarko’s liquids sales volumes were 316 thousand barrels per day (MBbls/d), representing a 9% increase over 2011.

 

   

The Company achieved an approximate 67% success rate from offshore exploration and appraisal drilling completed in 2012.

U.S. Onshore

 

   

The Rocky Mountains Region (Rockies) total-year sales volumes were 321 MBOE/d, representing a 6% increase over 2011, primarily from the Wattenberg field and the Greater Natural Buttes area.

 

   

The Southern and Appalachia Region total-year sales volumes were 198 MBOE/d, representing a 36% increase over 2011, primarily from the Marcellus, Eagleford, and Haynesville shales.

Gulf of Mexico

 

   

Gulf of Mexico total-year sales volumes were 116 MBOE/d, representing an 11% decrease from 2011, primarily due to natural production declines.

 

   

The Company achieved first production from the Caesar/Tonga development (33.75% working interest) in the Green Canyon area during March 2012, utilizing Anadarko’s Constitution spar floating production facility.

 

   

The Company entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development.

International

 

   

International total-year sales volumes were 84 MBOE/d, representing a 2% decrease from 2011.

 

   

The Company drilled five successful exploration wells: two in Mozambique and one each in Ghana, Côte d’Ivoire, and Sierra Leone.

 

   

The Company drilled ten successful appraisal wells: seven in Mozambique, two in Ghana, and one in Brazil.

Financial

 

   

Anadarko’s net income attributable to common stockholders for 2012, including $1.8 billion related to the favorable resolution of the Algeria exceptional profits tax dispute and $845 million of certain unproved property impairments, totaled $2.4 billion. In 2011, Anadarko’s net loss attributable to common stockholders was $2.6 billion, and included the effect of the $4.0 billion settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement).

 

   

The Company generated $8.3 billion of cash flows from operations in 2012, including $1.0 billion collected related to the resolution of the Algeria exceptional profits tax dispute, and ended 2012 with $2.5 billion of cash on hand. Anadarko’s $2.5 billion of cash flows from operations in 2011 included the effect of the $4.0 billion payment made as a result of the Settlement Agreement.

 

   

The Company fully repaid $2.5 billion of borrowings under its $5.0 billion Facility.

 

   

Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in Western Gas Partners, LP (WES), also a consolidated subsidiary of Anadarko, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit.

 

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The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the year ended December 31, 2012” refer to the comparison of the year ended December 31, 2012, to the year ended December 31, 2011. Similarly, any increases or decreases “for the year ended December 31, 2011” refer to the comparison of the year ended December 31, 2011, to the year ended December 31, 2010. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude oil, and natural gas liquids (NGLs); sales volumes; the Company’s ability to discover additional reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

Selected Data

 

millions except per-share amounts and percentages   2012     2011     2010  

Financial Results

     

Oil and condensate, natural-gas, and NGLs sales

  $ 12,396     $ 12,834     $ 10,009  

Gathering, processing, and marketing sales

    911       1,048       833  

Gains (losses) on divestitures and other, net

    104       85       142  
 

 

 

   

 

 

   

 

 

 

Total revenues and other

    13,411       13,967       10,984  

Costs and expenses (1)

    9,684       15,837       9,215  

Other (income) expense

    162       1,554       128  

Income tax expense (benefit)

    1,120       (856     820  

Net income (loss) attributable to common stockholders

  $ 2,391     $ (2,649   $ 761  

Net income (loss) per common share attributable to common
stockholders—diluted

  $ 4.74     $ (5.32   $ 1.52  

Average number of common shares outstanding—diluted

    502       498       497  

Operating Results

     

Adjusted EBITDAX (2)

  $ 8,966     $ 8,869     $ 7,146  

Total proved reserves (MMBOE)

    2,560       2,539       2,422  

Annual sales volumes (MMBOE)

    268       248       235  

Capital Resources and Liquidity

     

Cash provided by operating activities

  $ 8,339     $ 2,505     $ 5,247  

Capital expenditures

    7,311       6,553       5,169  

Total debt

    13,269       15,230       13,013  

Stockholders’ equity

  $ 20,629     $ 18,105     $ 20,684  

Debt to total capitalization ratio

    39.1%        45.7%        38.6%   

 

MMBOE—million barrels of oil equivalent

(1) 

Includes Deepwater Horizon settlement and related costs of $18 million in 2012, $3.9 billion in 2011, and $15 million in 2010, and a credit of $1.8 billion for previously recorded expenses related to the favorable resolution of the Algeria exceptional profits tax dispute in 2012.

(2) 

See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

 

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FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders  Anadarko’s net income attributable to common stockholders for 2012 totaled $2.4 billion, or $4.74 per share (diluted), compared to a net loss attributable to common stockholders for 2011 of $2.6 billion, or $5.32 per share (diluted). Anadarko’s net income attributable to common stockholders in 2010 was $761 million, or $1.52 per share (diluted). Anadarko’s net income for 2012 included $1.8 billion related to the favorable resolution of the exceptional profits tax dispute and $845 million related to certain unproved property impairments. Anadarko’s net loss for 2011 included the effect of the $4.0 billion Settlement Agreement with BP Exploration & Production Inc. (BP) related to the Deepwater Horizon events.

Sales Revenues and Volumes

 

                                                                                    
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Sales Revenues

         

Natural-gas sales

  $ 2,444       (26 )%    $ 3,300       (4 )%    $ 3,420  

Oil and condensate sales

    8,728       8       8,072       44       5,592  

Natural-gas liquids sales

    1,224       (16     1,462       47       997  
 

 

 

     

 

 

     

 

 

 

Total

  $ 12,396       (3   $ 12,834       28     $ 10,009  
 

 

 

     

 

 

     

 

 

 

Anadarko’s total sales revenues for the year ended December 31, 2012, decreased primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products. Total sales revenues for the year ended December 31, 2011, increased primarily due to higher prices for crude oil and NGLs, as well as increased liquids volumes, partially offset by lower average natural-gas prices.

 

                                                                                                   
millions   Natural
Gas
    Oil and
Condensate
    NGLs     Total  

2010 sales revenues

  $ 3,420     $ 5,592     $ 997     $ 10,009  

Changes associated with prices

    (214     2,055       295       2,136  

Changes associated with sales volumes

    94       425       170       689  
 

 

 

   

 

 

   

 

 

   

 

 

 

2011 sales revenues

  $ 3,300     $ 8,072     $ 1,462     $ 12,834  

Changes associated with prices

    (1,094     9       (409     (1,494

Changes associated with sales volumes

    238       647       171       1,056  
 

 

 

   

 

 

   

 

 

   

 

 

 

2012 sales revenues

  $ 2,444     $ 8,728     $ 1,224     $ 12,396  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table provides Anadarko’s sales volumes for the years ended December 31, 2012, 2011, and 2010:

 

                                                                          
Sales Volumes   2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Barrels of Oil Equivalent

         

(MMBOE except percentages)

         

United States

    237       9     217       4     209  

International

    31       (2     31       20       26  
 

 

 

     

 

 

     

 

 

 

Total

    268       8       248       6       235  
 

 

 

     

 

 

     

 

 

 

Barrels of Oil Equivalent per Day

         

(MBOE/d except percentages)

         

United States

    648       9     595       4     572  

International

    84       (2     85       20       71  
 

 

 

     

 

 

     

 

 

 

Total

    732       8       680       6       643  
 

 

 

     

 

 

     

 

 

 

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs is usually not affected by seasonal swings in demand.

Natural-Gas Sales Volumes, Average Prices, and Revenues

 

                                                                                    
    2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

United States

         

Sales volumes—Bcf

    913       7     852       3     829  

                            MMcf/d

    2,495       7       2,334       3       2,272  

Price per Mcf

  $ 2.68       (31   $ 3.87       (6   $ 4.12  

Natural-gas sales revenues (millions)

  $ 2,444       (26   $ 3,300       (4   $ 3,420  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes increased 161 MMcf/d for the year ended December 31, 2012, primarily due to higher sales volumes in the Southern and Appalachia Region of 220 MMcf/d as a result of bringing wells drilled in previous years online at Eagleford and Marcellus shales due to infrastructure expansions during 2012 and new wells drilled in the Haynesville shale. Also, the Company had higher sales volumes in the Rockies of 52 MMcf/d associated with drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were partially offset by reduced sales volumes in the Gulf of Mexico of 111 MMcf/d primarily due to natural production declines.

The Company’s natural-gas sales volumes increased 62 MMcf/d for the year ended December 31, 2011, primarily due to higher sales volumes in the Rockies of 84 MMcf/d, resulting from increased drilling in the Greater Natural Buttes area and the Wattenberg field, as well as higher sales volumes in the Southern and Appalachia Region of 66 MMcf/d, primarily related to increased drilling in the Marcellus shale. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 86 MMcf/d, primarily due to 2010 price-related royalty relief that did not apply in 2011 and natural production declines.

 

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The average natural-gas price Anadarko received decreased for the year ended December 31, 2012, due to continued growth in U.S. natural-gas production, reduced U.S. natural-gas demand as a result of mild winter temperatures, and above-average U.S. natural-gas storage levels in 2012. Anadarko’s average natural-gas price received decreased for the year ended December 31, 2011, primarily due to the industry’s supply growing at a faster pace than demand in 2011.

Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues

 

                                                                                    
    2012     Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

United States

         

Sales volumes—MMBbls

    55       14     48       1     48  

                            MBbls/d

    149       14       132       1       130  

Price per barrel

  $ 97.46           $ 97.70       30     $ 74.96  

International

         

Sales volumes—MMBbls

    31       (2 )%      31       20     26  

                            MBbls/d

    84       (2     85       20       71  

Price per barrel

  $ 111.11       2     $ 109.20       39     $ 78.52  

Total

         

Sales volumes—MMBbls

    86       8     79       8     74  

                            MBbls/d

    233       8       217       8       201  

Price per barrel

  $ 102.35           $ 102.24       34     $ 76.22  

Oil and condensate sales revenues (millions)

  $ 8,728       8     $ 8,072       44     $ 5,592  

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d for the year ended December 31, 2012. Increased horizontal drilling in the Wattenberg field led to a 9 MBbls/d sales-volume improvement in the Rockies. Horizontal drilling in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 8 MBbls/d.

Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d for the year ended December 31, 2011. This increase primarily resulted from an additional 15 MBbls/d in Ghana, where the Company’s first lifting occurred in the first quarter of 2011. Increased drilling in the Wattenberg field led to a 5 MBbls/d sales-volume improvement in the Rockies. Additionally, increased activity in the Eagleford shale and Bone Spring/Avalon formations increased sales volumes from those areas by approximately 170%, contributing to an 8 MBbls/d sales-volume increase in the Southern and Appalachian Region. Partially offsetting these increases was a 9 MBbls/d sales-volume decline in the Gulf of Mexico principally caused by downtime for repairs at the Company’s Constitution spar and a third-party oil pipeline in 2011, and natural production declines.

Anadarko’s average crude-oil price received increased for the years ended December 31, 2012 and 2011, primarily due to supply disruption concerns associated with political and civil unrest in the Middle East and North Africa, and steady global demand growth. Additionally, average realized crude-oil prices for 2012 and 2011 were enhanced by the wide differential between West Texas Intermediate and Brent crude, as approximately 70% of Anadarko’s crude-oil sales volumes were based on prices that were either directly indexed to, or highly correlated to, Brent crude. The price increase for the year ended December 31, 2012, was offset by downward price pressure caused by macroeconomic concerns in Europe and China.

 

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Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues

 

                                                                                                        
    2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

United States

         

Sales volumes—MMBbls

    30       12     27       17     23  

                                   MBbls/d

    83       12       74       17       63  

Price per barrel

  $ 40.44       (25   $ 53.95       25     $ 43.07  

Natural-gas liquids sales revenues (millions)

  $ 1,224       (16   $ 1,462       47     $ 997  

NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 9 MBbls/d for the year ended December 31, 2012, as a result of drilling in liquids-rich areas, primarily in the Eagleford and Haynesville shales in the Southern and Appalachia Region.

Anadarko’s NGLs sales volumes increased by 11 MBbls/d for the year ended December 31, 2011, as a result of the Company’s increased focus on liquids-rich areas, expanded horizontal drilling programs in the Wattenberg field, and increases related to the acquisition of an additional 93% interest in a natural-gas processing plant (Wattenberg Plant).

Anadarko’s average NGLs price decreased for the year ended December 31, 2012, primarily due to lower market prices for ethane and propane. Ethane demand was reduced by down-time for maintenance and conversion upgrades at petrochemical facilities. Mild winter temperatures across much of the United States in 2011 reduced demand for propane and contributed to above-average levels of propane stockpiles. Also, increased production from continued liquids-rich development has created further downward pricing pressures for NGLs. The average NGLs price increased for the year ended 2011, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing, and Marketing Margin

 

                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Gathering, processing, and marketing sales

  $ 911       (13)   $ 1,048       26   $ 833  

Gathering, processing, and marketing expenses

    763       (4)         791       29       615  
 

 

 

     

 

 

     

 

 

 

Margin

  $ 148       (42)       $ 257       18     $ 218  
 

 

 

     

 

 

     

 

 

 

For the year ended December 31, 2012, the gathering, processing, and marketing margin decreased $109 million. This decrease was due primarily to lower commodity prices, which led to reduced natural-gas processing margins and decreased marketing margins on sales from inventory. Also, for the year ended December 31, 2012, transportation expenses increased primarily due to higher unutilized demand fees. These decreases for the year ended December 31, 2012, were partially offset by additional margin provided by midstream assets acquired in February 2011 and May 2011, and an increase in gathering and processing revenues associated with increased throughput volumes across several of Anadarko’s fee-based systems.

For the year ended December 31, 2011, the gathering, processing, and marketing margin increased $39 million. This increase was primarily due to increased natural-gas processing margins from higher NGLs prices and volumes, lower prices for natural-gas purchases, and favorable impacts attributable to 2011 asset acquisitions discussed above. These increases were partially offset by lower margins associated with natural-gas sales from inventory.

 

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Gains (Losses) on Divestitures and Other, net

For the year ended December 31, 2012, gains (losses) on divestitures and other, net increased $19 million primarily due to increased mineral revenue of $36 million related to increased mining of soda ash on Anadarko’s Land Grant and higher per-ton average sales prices. Increased mineral revenue was partially offset by an increase in net losses on divestitures of $17 million. In January 2013, the Company divested its equity interest in the OCI soda ash business for $310 million and additional potential consideration while retaining its royalty interest in minerals mined from the Company’s Land Grant.

Gains (losses) on divestitures for 2012 included net losses of $71 million, primarily related to the sale of oil and gas exploration and production reporting segment properties in Indonesia.

Gains (losses) on divestitures for 2011 included net losses of $54 million, primarily related to write-downs of $422 million of assets held for sale. In 2011, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. Also included in 2011 was a $76 million loss, which occurred in connection with the Company’s purchase of the Wattenberg Plant. This loss was associated with the effective elimination, for purposes of consolidated financial reporting, of a pre-existing third-party relationship between the Company and the previous owner of the plant related to natural-gas processing contracts. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to market transactions for the same or similar services at the date of the Company’s acquisition of the plant. These losses were partially offset by 2011 gains of $419 million for receipt and final settlement of contingent consideration related to the 2008 divestiture of its interest in the Peregrino field offshore Brazil and $21 million from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant.

For the year ended December 31, 2011, gains (losses) on divestitures and other, net decreased $57 million primarily due to 2011 net losses on divestitures discussed above.

Costs and Expenses

 

                                                                                                        
    2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Oil and gas operating (millions)

  $ 976       (2)   $ 993       20   $ 830  

Oil and gas operating—per BOE

    3.65       (9)         4.00       13       3.54  

Oil and gas transportation and other (millions)

    955              891       9       816  

Oil and gas transportation and other—per BOE

    3.57       (1)         3.59       3       3.48  

For the year ended December 31, 2012, oil and gas operating expenses decreased by $17 million primarily due to lower workover expenses of $67 million associated with fewer workovers, primarily in the Gulf of Mexico and the Rockies, partially offset by $52 million of higher operating expenses from increased activity in Ghana. Per-BOE oil and gas operating expenses decreased by $0.35 for the year ended December 31, 2012, primarily as a result of increased sales volumes, while efficiently maintaining production costs, and lower workover expenses discussed above. For the year ended December 31, 2011, oil and gas operating expenses increased by $163 million primarily due to (i) $47 million from increased workovers and related freight costs, primarily in the Gulf of Mexico and the Rockies, (ii) $36 million related to increased joint-venture activity primarily in the Rockies, Bone Spring and Marcellus shale in the Southern and Appalachia Region, and in Alaska, (iii) $34 million in operating costs resulting from the start of production in Ghana, and (iv) $10 million in higher surface maintenance costs primarily in the Rockies. Oil and gas operating expenses per BOE increased by $0.46 for the year ended December 31, 2011, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

 

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For the year ended December 31, 2012, oil and gas transportation and other expenses increased $64 million primarily due to higher gas-gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. For the year ended December 31, 2011, oil and gas transportation and other expenses increased $75 million due to higher volumes, higher natural-gas processing fees that rise with increases in NGLs prices, and increased costs attributable to growth in U.S. onshore plays. These increases were partially offset by the 2010 expensing of amounts attributable to drilling rig lease payments for rigs that sat idle during the moratorium, as well as rig termination fees incurred in 2010 related to deepwater drilling rigs in the Gulf of Mexico. Oil and gas transportation and other expenses per BOE decreased by $0.02 for the year ended December 31, 2012, primarily due to increased sales volumes, partially offset by the higher costs discussed above. For the year ended December 31, 2011, oil and gas transportation and other expenses per BOE increased by $0.11, primarily due to the higher costs discussed above, partially offset by increased sales volumes.

 

                                                  
millions   2012     2011     2010  

Exploration Expense

     

Dry hole expense

  $ 440     $ 154     $ 202  

Impairments of unproved properties

    1,104       471       480  

Geological and geophysical expenses

    151       246       103  

Exploration overhead and other

    251       205       189  
 

 

 

   

 

 

   

 

 

 

Total exploration expense

  $ 1,946     $ 1,076     $ 974  
 

 

 

   

 

 

   

 

 

 

Exploration expense increased $870 million for the year ended December 31, 2012, primarily due to increases of $633 million in impairments of unproved properties and $286 million in dry hole expense, partially offset by a $95 million decrease in geological and geophysical expenses.

The increase in 2012 impairments of unproved properties was primarily due to $845 million of impairments for certain unproved properties in the Rockies and the Gulf of Mexico. Approximately $721 million of the impairments were due to lower natural-gas prices associated with Powder River coalbed methane properties in the Rockies and $124 million related to a Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment. These increases were partially offset by 2011 impairments of certain unproved properties in the Gulf of Mexico of $124 million and Indonesia of $63 million due to decreases in the estimated recoverable cash flows.

The $286 million increase in dry hole expense for the year ended December 31, 2012, was primarily due to wells in Brazil, Sierra Leone, Côte d’Ivoire, Mozambique, and the Gulf of Mexico. The $95 million decrease in geological and geophysical expense was primarily due to fewer seismic purchases in Kenya, Liberia, New Zealand, and Mozambique.

For the year ended December 31, 2012, exploration overhead and other increased $46 million primarily due to increased exploration activity onshore United States and in Mozambique.

Exploration expense increased $102 million for the year ended December 31, 2011, due to $143 million of higher geological and geophysical expense, primarily associated with increased seismic purchases in the Rockies, Gulf of Mexico, the Marcellus shale, Indonesia, Liberia, and East Africa. These additional expenses were partially offset by $48 million of lower dry hole expense, primarily in the Gulf of Mexico.

 

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Index to Financial Statements
                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

General and administrative

  $ 1,246       18   $ 1,060       10   $ 967  

Depreciation, depletion, and amortization

    3,964       3       3,830       3       3,714  

Other taxes

    1,224       (18     1,492       40       1,068  

Impairments

    389       (78     1,774       NM        216  

 

NM—not meaningful

For the year ended December 31, 2012, general and administrative (G&A) expense increased by $186 million due to higher employee-related expenses of $150 million primarily related to expense associated with general partner Unit Appreciation Rights (UARs) awarded in prior years to certain officers of the general partner of WES, pursuant to the WGH Equity Incentive Plan. This increase was related to the change in fair value of the UARs upon the WGP IPO. In addition, G&A expense increased by $41 million due to higher legal-related and consulting expenses primarily related to the Tronox litigation. For the year ended December 31, 2011, G&A expense increased by $93 million primarily due to higher employee-related costs of $67 million primarily from operational expansions and changes in pension discount rates, and increased insurance costs of $9 million related to higher industry-specific rates as a result of the Deepwater Horizon events.

For the year ended December 31, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $134 million primarily due to higher sales volumes, accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, and the start of production at Caesar/Tonga in March 2012. These increases were partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and reserves additions in 2012 related to the Southern and Appalachia Region. For the year ended December 31, 2011, DD&A expense increased by $116 million primarily attributable to higher sales volumes, partially offset by a lower average DD&A rate, largely the result of an $89 million DD&A expense recognized in 2010 associated with depleted fields in the Gulf of Mexico.

For the year ended December 31, 2012, other taxes decreased by $268 primarily related to lower Algeria exceptional profits taxes of $184 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute. Other taxes also decreased due to lower commodity prices, which resulted in lower U.S. production and severance taxes of $55 million, and lower ad valorem taxes of $27 million. For the year ended December 31, 2011, other taxes increased by $424 million primarily due to higher crude-oil prices and total sales volumes, resulting in increased Algerian exceptional profits tax of $172 million, increased U.S. production and severance taxes of $152 million, and increased Chinese windfall profits tax of $55 million. Additionally, ad valorem taxes increased by $46 million in 2011 due to higher assessed property values.

Impairment expense was $389 million for the year ended December 31, 2012. The Company recognized impairments of $363 million related to oil and gas exploration and production reporting segment properties located in the United States, $13 million related to midstream properties, and $13 million related to the Company’s Venezuelan cost-method investment. Impairment expense for U.S. oil and gas exploration and production reporting segment properties included $259 million related to lower natural-gas prices. Impairment expense for U.S. properties also included $79 million related to downward reserves revisions for a Gulf of Mexico property that was near the end of its economic life and $25 million for a platform in the Gulf of Mexico with no salvage value. Also during 2012, the Company recognized impairment expense of $13 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable reserves and lower crude-oil prices. Further declines in commodity prices or negative reserves revisions could result in additional impairments. See Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices.

 

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Impairment expense of $1.8 billion for the year ended December 31, 2011, included $1.2 billion related to oil and gas exploration and production reporting segment properties located in the United States, $458 million for midstream reporting segment properties, and $91 million related to the Company’s Venezuelan cost-method investment. Impairment expense of $952 million for U.S. onshore oil and gas properties and $446 million for associated midstream properties was triggered by lower natural-gas prices. Impairment expense also included $162 million for certain Gulf of Mexico properties related to declines in estimated recoverable reserves, and $100 million related to onshore properties due to changes in projected cash flows resulting from the Company’s intent to divest of the subject properties. All of these assets were impaired to fair value.

Impairment expense for the year ended December 31, 2010, included $114 million related to a production platform included in the oil and gas exploration and production reporting segment that remains idle with no immediate plan for use, and for which a limited market exists, and $61 million related to the Company’s Venezuelan cost-method investment.

 

                                                  
millions   2012     2011     2010  

Algeria exceptional profits tax settlement

  $ (1,797   $     $   

Deepwater Horizon settlement and related costs

    18       3,930       15  

In March 2012, Anadarko and Sonatrach resolved the exceptional profits tax dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the year ended December 31, 2012, to reflect the effect of this agreement for previously recorded expenses. During 2012, the Company collected $1.0 billion associated with the Algeria exceptional profits tax receivable. The Company expects to collect the balance of the Algeria exceptional profits tax receivable during the first half of 2013.

In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company agreed to pay $4.0 billion in cash and transfer its interest in the Macondo well and the Mississippi Canyon Block 252 lease (Lease) to BP, and BP agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued through the settlement date as well as for potential reimbursements of subsequent costs incurred by BP related to the Deepwater Horizon events, including costs under the Operating Agreement (OA). In addition, BP fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative, or security laws claims, or certain other claims. The Company believes that costs associated with any non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows. Refer to Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion and analysis of these events.

 

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For the year ended December 31, 2012, Deepwater Horizon settlement and related costs included $18 million of legal expenses and related costs associated with the Deepwater Horizon events. For the year ended December 31, 2011, Deepwater Horizon settlement and related costs included a $4.0 billion expense for the Company’s cash payment made to BP pursuant to the Settlement Agreement discussed above, as well as $93 million of legal expenses and other related costs associated with the Deepwater Horizon events. These amounts were partially offset by a $163 million gain recognized in the fourth quarter of 2011 for insurance recoveries associated with the Deepwater Horizon events. Although Anadarko has been indemnified by BP for certain costs, the Company may be required to recognize a liability for amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. Additionally, as part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, equal to 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion 2011 payment made to BP as part of the Settlement Agreement.

Other (Income) Expense

 

                                                                                                        
millions except percentages       2012         Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Interest Expense

         

Current debt, long-term debt, and other

  $ 963       (2 )%    $ 986       13   $ 871  

(Gain) loss on early debt retirements and commitment termination

          NM              (100     112  

Capitalized interest

    (221     (50     (147     (15     (128
 

 

 

     

 

 

     

 

 

 

Interest expense

  $ 742       (12   $ 839       (2   $ 855  
 

 

 

     

 

 

     

 

 

 

Anadarko’s interest expense decreased $97 million for the year ended December 31, 2012, primarily due to an increase in capitalized interest of $74 million related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the year ended December 31, 2012, decreased $32 million as a result of interest incurred during 2011 related to the Company’s capital lease obligations for a floating production, storage, and offloading vessel (FPSO) for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the vessel, resulting in cancellation of the capital lease obligation.

Anadarko’s interest expense decreased for the year ended December 31, 2011, due to $19 million of increased capitalized interest related to higher construction-in-progress balances for long-term capital projects. Additionally, 2011 interest expense was lower due to items that occurred in 2010 with no similar expense in 2011, including $86 million associated with losses on early debt retirements, $17 million of commitment and structuring costs associated with a contemplated term-loan facility, and $9 million related to unamortized debt issuance costs recognized with the retirement of the Midstream Subsidiary Note Payable to a Related Party. These items were partially offset by $48 million from a higher average outstanding debt balance and weighted-average interest rate on outstanding debt, $29 million related to interest on capital lease obligations incurred in 2011, $24 million attributable to increased amortization of debt-issuance and credit-facility origination costs, and $20 million of higher fees on issued letters of credit and commitment fees related to the $5.0 billion Facility. For additional information, see Liquidity and Capital Resources—Uses of Cash—Debt Retirements and Repayments, and Interest-Rate Risk under Item 7A of this Form 10-K.

 

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Index to Financial Statements
                                                  
millions   2012     2011     2010  

(Gains) Losses on Derivatives, net

     

Commodity derivatives

     

Realized (gains) losses

     

Natural gas

  $ (678   $ (288   $ (513

Oil and condensate

    (65     61       15  

Natural gas liquids

    (10     1        
 

 

 

   

 

 

   

 

 

 

Total realized (gains) losses

    (753     (226     (498
 

 

 

   

 

 

   

 

 

 

Unrealized (gains) losses

     

Natural gas

    444       (192     (353

Oil and condensate

    (64     (140     (42

Natural gas liquids

    (14     (4      
 

 

 

   

 

 

   

 

 

 

Total unrealized (gains) losses

    366       (336     (395
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on commodity derivatives, net

    (387     (562     (893
 

 

 

   

 

 

   

 

 

 

Interest-rate and other derivatives

     

Realized (gains) losses

    66       59        

Unrealized (gains) losses

    (5     964       285  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on interest-rate and other derivatives, net

    61       1,023       285  
 

 

 

   

 

 

   

 

 

 

Total (gains) losses on derivatives, net

  $ (326   $ 461     $ (608
 

 

 

   

 

 

   

 

 

 

The Company enters into commodity derivatives to manage the risk of a decrease in the market prices for its anticipated sales of production. The change in (gains) losses on commodity derivatives, net includes the impact of derivatives entered into or settled during the year and price changes related to positions open at December 31 of each year. For additional information on (gains) losses on commodity derivatives, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease). In 2012, the Company extended the swap maturity dates from October 2012 to September 2016 for interest-rate swaps with an aggregate notional principal amount of $800 million. In 2011, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were settled in October 2012, resulting in a realized loss of $64 million, and interest-rate swap agreements with an aggregate notional principal amount of $150 million were settled in October 2011, resulting in a realized loss of $57 million. For additional information, see Note 12—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements
                                                                                                        
millions except percentages       2012         Inc/(Dec)
  vs. 2011  
        2011         Inc/(Dec)
  vs. 2010  
        2010      

Other (Income) Expense, net

         

Interest income

  $ (16     (24 )%    $ (21     62   $ (13

Other

    (238     187       275       NM        (106
 

 

 

     

 

 

     

 

 

 

Total other (income) expense, net

  $ (254     NM      $ 254       NM      $ (119
 

 

 

     

 

 

     

 

 

 

Total other income increased $508 million for the year ended December 31, 2012, primarily due to the $250 million reversal of the Tronox-related contingent loss recognized in 2011. See Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

For 2011, total other income decreased $373 million, primarily due to the recognition of a $250 million Tronox-related contingent loss in 2011, and the 2010 reversal of the $95 million reimbursement obligation to Tronox as a result of the cancellation of the Master Separation Agreement (MSA) by Tronox that occurred as part of Tronox’s bankruptcy proceedings. Additionally, total other income in 2011 decreased $20 million due to unfavorable exchange-rate changes applicable to foreign currency purchased in anticipation of funding future expenditures on major development projects and foreign currency held in escrow at December 31, 2011, pending final determination of the Company’s Brazilian tax liability from its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently under consideration by the Brazilian courts, and the Company expects this litigation to be resolved within the next year. An unfavorable decision may require the Company to record a tax liability in the Consolidated Financial Statements. See Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Income Tax Expense

 

                                                  
millions except percentages   2012     2011     2010  

Income tax expense (benefit)

  $ 1,120     $ (856   $ 820  

Effective tax rate

    31%        25%        50%   

The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2012, was primarily attributable to the resolution of the Algerian exceptional profits tax dispute. This amount was partially offset by the following:

 

   

Algerian exceptional profits taxes

 

   

tax impact from foreign operations

The Company reported a loss before income taxes for the year ended December 31, 2011. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2011, was primarily attributable to the following:

 

   

Algerian exceptional profits taxes

 

   

tax impact from foreign operations

 

   

items resulting from business acquisitions and other items

These amounts were partially offset by state income tax benefits of the loss.

The increase from the 35% U.S. federal statutory rate for the year ended December 31, 2010, was primarily attributable to the following:

 

   

Algerian exceptional profits taxes

 

   

unfavorable resolution of uncertain tax positions

 

   

tax impact from foreign operations

For additional information on income tax rates, see Note 19—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Net Income Attributable to Noncontrolling Interests

In December 2012, WGP completed its IPO of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit. The Company’s net income attributable to noncontrolling interests of $54 million for the year ended December 31, 2012, $81 million for 2011, and $60 million for 2010, primarily related to public ownership interests in WES and WGP. Public ownership of WES was 51.8% at December 31, 2012, 54.7% at December 31, 2011, and 51.5% at December 31, 2010. Public ownership of WGP was 9.0% at December 31, 2012. See Note 10—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements

OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX  To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes, interest expense, exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, unrealized (gains) losses on derivatives, net, and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of these events. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes, and consolidated Adjusted EBITDAX by reporting segment.

 

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Index to Financial Statements

Adjusted EBITDAX

 

                                                                                                        
millions except percentages   2012     Inc/(Dec)
  vs. 2011  
    2011     Inc/(Dec)
  vs. 2010  
    2010  

Income (loss) before income taxes

  $ 3,565       NM      $ (3,424     NM      $ 1,641  

Exploration expense

    1,946       81     1,076       10     974  

DD&A

    3,964       3        3,830       3        3,714  

Impairments

    389       (78     1,774       NM        216  

Deepwater Horizon settlement and related costs

    18       (100     3,930       NM        15  

Algeria exceptional profits tax settlement (1)

    (1,797     NM              NM         

Tronox-related contingent loss (1)

    (250     NM        250       NM        (95

Interest expense

    742       (12     839       (2     855  

Unrealized (gains) losses on derivatives, net

    377       (39     616       NM        (114

Realized (gains) losses on other derivatives, net (1)

    66       12        59       NM         

Less net income attributable to noncontrolling interests

    54       (33     81       35        60  
 

 

 

     

 

 

     

 

 

 

Consolidated Adjusted EBITDAX

  $ 8,966       1      $ 8,869       24 <